OHIO EDISON COMPANY

                       2003 ANNUAL REPORT TO STOCKHOLDERS



           Ohio Edison Company is a wholly owned electric utility operating
subsidiary of FirstEnergy Corp. Ohio Edison engages in the generation,
distribution and sale of electric energy to communities in an area of 7,500
square miles in central and northeastern Ohio and, through its wholly owned
Pennsylvania Power Company subsidiary, 1,500 square miles in western
Pennsylvania. It also engages in the sale, purchase and interchange of electric
energy with other electric companies.







Contents                                                                Page
--------                                                                ----

Selected Financial Data............................................       1
Management's Discussion and Analysis...............................      2-13
Consolidated Statements of Income..................................      14
Consolidated Balance Sheets........................................      15
Consolidated Statements of Capitalization..........................     16-17
Consolidated Statements of Common Stockholder's Equity.............      18
Consolidated Statements of Preferred Stock.........................      18
Consolidated Statements of Cash Flows..............................      19
Consolidated Statements of Taxes...................................      20
Notes to Consolidated Financial Statements.........................     21-39
Reports of Independent Auditors....................................     40-41



<PAGE>


<TABLE>
<CAPTION>


                               OHIO EDISON COMPANY

                             SELECTED FINANCIAL DATA


                                                      2003         2002          2001         2000        1999
-------------------------------------------------------------------------------------------------------------------
                                                                           (In thousands)

<S>                                                <C>          <C>          <C>          <C>           <C>
Operating Revenues..........................       $2,925,832   $2,948,675   $3,056,464   $2,726,708    $2,686,949
                                                   ---------------------------------------------------------------
Operating Income............................       $  335,727   $  453,831   $  466,819   $  482,321    $  473,042
                                                   ---------------------------------------------------------------
Income Before Cumulative Effect of
   Accounting Change........................       $  292,925   $  356,159   $  350,212   $  336,456    $  297,689
                                                   ----------- ----------------------------------------------------
Net Income..................................       $  324,645   $  356,159   $  350,212   $  336,456    $  297,689
                                                   ---------------------------------------------------------------
Earnings on Common Stock....................       $  321,913   $  349,649   $  339,510   $  325,332    $  286,142
                                                   ---------------------------------------------------------------
Total Assets................................       $7,316,930   $7,790,041   $7,915,953   $8,154,151    $8,700,746
                                                   ---------------------------------------------------------------

Capitalization as of December 31:
   Common Stockholder's Equity..............       $2,582,970   $2,839,255   $2,671,001   $2,556,992    $2,624,460
   Preferred Stock:
     Not Subject to Mandatory Redemption....          100,070      100,070      200,070      200,070       200,070
     Subject to Mandatory Redemption........               --       13,500      134,250      135,000       140,000
   Long-Term Debt...........................        1,179,789    1,219,347    1,614,996    2,000,622     2,175,812
                                                   ---------------------------------------------------------------
     Total Capitalization...................       $3,862,829   $4,172,172   $4,620,317   $4,892,684    $5,140,342
                                                   ---------------------------------------------------------------

Capitalization Ratios:
   Common Stockholder's Equity..............             66.9%        68.1%        57.8%        52.3%         51.1%
   Preferred Stock:
     Not Subject to Mandatory Redemption....              2.6          2.4          4.3          4.1           3.9
     Subject to Mandatory Redemption........             --            0.3          2.9          2.7           2.7
   Long-Term Debt...........................             30.5         29.2         35.0         40.9          42.3
                                                   ---------------------------------------------------------------
     Total Capitalization...................            100.0%       100.0%       100.0%       100.0%        100.0%
                                                   ---------------------------------------------------------------

Distribution Kilowatt-Hour Deliveries
 (Millions):
   Residential..............................           10,009       10,233        9,646        9,432         9,483
   Commercial...............................            8,105        7,994        7,967        8,221         8,238
   Industrial...............................           10,658       10,672       10,995       11,631        11,310
   Other....................................              160          154          152          151           151
                                                   ---------------------------------------------------------------
   Total....................................           28,932       29,053       28,760       29,435        29,182
                                                   ---------------------------------------------------------------

Customers Served:
   Residential..............................        1,044,419    1,041,825    1,033,414    1,014,379     1,016,793
   Commercial...............................          127,856      119,771      118,469      116,931       115,581
   Industrial...............................            1,182        4,500        4,573        4,569         4,627
   Other....................................            1,752        1,756        1,664        1,606         1,539
                                                   ---------------------------------------------------------------
   Total....................................        1,175,209    1,167,852    1,158,120    1,137,485     1,138,540
                                                   ---------------------------------------------------------------

Number of Employees ........................            1,521        1,569        1,618        1,647         2,734


</TABLE>


                                                             1



<PAGE>


                               OHIO EDISON COMPANY

                           MANAGEMENT'S DISCUSSION AND
                        ANALYSIS OF RESULTS OF OPERATIONS
                             AND FINANCIAL CONDITION


           This discussion includes forward-looking statements based on
information currently available to management. Such statements are subject to
certain risks and uncertainties. These statements typically contain, but are not
limited to, the terms "anticipate," "potential," "expect," "believe," "estimate"
and similar words. Actual results may differ materially due to the speed and
nature of increased competition and deregulation in the electric utility
industry, economic or weather conditions affecting future sales and margins,
changes in markets for energy services, changing energy and commodity market
prices, replacement power costs being higher than anticipated or inadequately
hedged, maintenance costs being higher than anticipated, legislative and
regulatory changes (including revised environmental requirements), adverse
regulatory or legal decisions and the outcome of governmental investigations,
availability and cost of capital, the continuing availability and operation of
generating units, the inability to accomplish or realize anticipated benefits
from strategic goals, the ability to improve electric commodity margins and to
experience growth in the distribution business, the ability to access the public
securities market, further investigation into the causes of the August 14, 2003,
regional power outage and the outcome, cost and other effects of present and
potential legal and administrative proceedings and claims related to the outage,
a denial of or material change to the Company's Application related to its Rate
Stabilization Plan, and other similar factors.

Restatements
------------

           We restated our financial statements for the year ended December 31,
2002, to reflect a change in the method of amortizing the costs associated with
the Ohio transition plan. Financial comparisons described below reflect the
effect of these restatements on 2002 financial results.

Results of Operations
---------------------

           Earnings on common stock in 2003 decreased to $321.9 million from
$349.6 million in 2002 and $339.5 million in 2001. The earnings decrease in 2003
primarily resulted from increased nuclear outage related costs, increased
amortization of the Ohio transition regulatory assets and reduced operating
revenues. These items were partially offset by reduced nuclear fuel expenses as
a result of the additional nuclear outages, reduced financing costs and an after
tax credit of $31.7 million from the cumulative effect of an accounting change
due to the adoption of SFAS 143, "Accounting for Asset Retirement Obligations."
Income before the cumulative effect was $292.9 million in 2003, compared to
$356.2 million for 2002 and $350.2 million for 2001.

           Operating revenues decreased by $22.8 million or 0.7% in 2003
compared with 2002 due to cooler-than-normal temperatures in the second and
third quarters of 2003 and increased sales by alternative suppliers. The lower
revenues primarily resulted from reduced generation sales revenues, which
included all retail customer categories - residential, commercial and
industrial. Kilowatt-hour sales to retail customers declined by 8.1% in 2003
from the prior year, reducing generation sales revenue by $98.0 million.
Electric generation services provided to retail customers by alternative
suppliers as a percent of total kilowatt-hours delivered in the Company's
franchise area increased 6.1 percentage points in 2003 from last year.

           Operating revenues decreased by $107.8 million or 3.5% in 2002
compared with 2001. The lower revenues reflected the effects of a sluggish
national economy on our service area, shopping by Ohio customers for alternative
energy providers and changes in wholesale revenues. Retail kilowatt-hour sales
declined by 8.7% in 2002 from the prior year, with declines in all customer
sectors (residential, commercial and industrial), resulting in a $73.1 million
reduction in generation sales revenue. Our lower generation kilowatt-hour sales
resulted primarily from customer choice in Ohio. Sales of electric generation by
alternative suppliers as a percent of total sales delivered in our franchise
area increased to 20.9% in 2002 from 12.5% in 2001, while our share of electric
generation sales in our franchise areas decreased by 8.4% compared to the prior
year.

           Distribution revenues from electricity throughput increased by $35.3
million in 2003 for all retail customer classes compared with 2002, primarily
due to higher unit prices partially offset by the effects of slightly lower
distribution deliveries in 2003. Distribution deliveries increased 1.0% in 2002
compared with 2001, which increased revenues from electricity throughput by
$18.5 million in 2002 from the prior year. The higher distribution deliveries
resulted from additional residential demand due to warmer summer weather that
was offset in part by the effect that continued sluggishness in the economy had
on demand by commercial and industrial customers.

           Operating revenues were further reduced in 2003 as a result of the
Ohio transition plan incentives provided to customers to promote customer
shopping for alternative suppliers - $8.1 million of additional credits in 2003
compared to


                                        2


$27.6  million of  additional  credits in 2002 from 2001.  These  reductions  in
revenues are deferred for future  recovery under the Company's  transition  plan
and do not materially affect current period earnings.

           Sales revenues from wholesale customers increased by $46.7 million in
2003 compared with 2002. This reflected the effect of higher unit prices, which
was partially offset by lower kilowatt-hour sales to the wholesale market due to
reduced nuclear generation available for sale to FirstEnergy Solutions (FES), an
affiliated company. Sales revenues from wholesale customers decreased by $18.0
million in 2002 compared to 2001, due to a decline in market prices.

           Changes in electric generation sales and distribution deliveries in
2003 compared to 2002 are summarized in the following table:

  Changes in Kilowatt-Hour Sales                2003            2002
  ----------------------------------------------------------------------
  Increase (Decrease)
  Electric Generation:
    Retail...............................      (8.1)%          (8.7)%
    Wholesale............................     (10.5)%          10.6%
--------------------------------------------------------------------
  Total Electric Generation Sales........      (9.2)%          (0.6)%
  ===================================================================
  Distribution Deliveries:
    Residential..........................      (2.2)%           6.1%
    Commercial...........................       1.4%            0.3%
    Industrial...........................      (0.1)%          (2.9)%
---------------------------------------------------------------------
  Total Distribution Deliveries..........      (0.4)%           1.0%
  ==================================================================


       Operating Expenses and Taxes

           Total operating expenses and taxes increased by $95.3 million in 2003
and decreased by $94.8 million in 2002 from 2001. The following table presents
changes from the prior year by expense category.


 Operating Expenses and Taxes - Changes            2003         2002
 ---------------------------------------------------------------------
 Increase (Decrease)                                  (In millions)
 Fuel and purchased power.....................    $(19.9)    $ (109.6)
 Nuclear operating costs......................      80.2        (28.9)
 Other operating costs........................       1.3         51.3
 --------------------------------------------------------------------
   Total operation and maintenance expenses...      61.6        (87.2)

 Provision for depreciation and amortization..      52.6        (39.4)
 General taxes................................      (6.9)        23.5
 Income taxes.................................     (12.0)         8.3
 --------------------------------------------------------------------
   Total operating expenses and taxes.........    $ 95.3       $(94.8)
 =====================================================================


           Lower fuel costs in 2003 compared to 2002 resulted from reduced
nuclear generation - down 10.5%. In 2003, the kilowatt-hour purchase
requirements were lower than in 2002 because of reduced electric generation
sales - those cost reductions were partially offset by the effect of higher unit
costs. Higher nuclear operating costs in 2003 were driven by three nuclear
refueling outages in 2003 - Beaver Valley Unit 1 (100% interest), Beaver Valley
Unit 2 (55.62% interest) and the Perry Plant (35.24% interest) in 2003 compared
with one refueling outage at Beaver Valley Unit 2 in 2002. The Beaver Valley
Unit 1 and Perry refueling outages earlier in 2003 included additional unplanned
work, which extended the length of the outages and increased their cost.

           Charges for depreciation and amortization increased by $52.6 million
in 2003 compared to 2002 primarily from increased amortization of the Ohio
transition regulatory assets ($57.9 million) and reduced transition plan
regulatory asset deferrals ($27.3 million) in 2003. Partially offsetting these
increases were higher shopping incentive deferrals ($8.1 million) and lower
charges resulting from the implementation of SFAS 143 ($18.5 million),
"Accounting for Asset Retirement Obligations." In 2002, depreciation and
amortization decreased by $39.4 million compared to 2001 primarily due to higher
shopping incentive deferrals and tax-related deferrals under the Ohio transition
plan.

           General taxes decreased by $6.9 million in 2003 from 2002 principally
due to settled property tax claims partially offset by higher kilowatt-hour
taxes in Ohio. In 2002, general taxes increased by $23.5 million in 2002 from
2001 principally due to additional property taxes and the absence in 2002 of a
one-time benefit of $15 million resulting from the successful resolution of
certain property tax issues in the prior year.

                                        3
<PAGE>


       Other Income

           Other income increased by $25.1 million in 2003 from the prior year,
primarily due to the absence in 2003 of adjustments recorded in 2002 related to
low-income housing investments.

       Net Interest Charges

           Net interest charges continued to trend lower, decreasing by $29.7
million in 2003 and by $44.8 million in 2002. We continued to redeem and
refinance outstanding debt and preferred stock during 2003 - net redemptions and
refinancing activities totaled $245.1 million and $542.0 million, respectively,
and will result in annualized savings of $20.2 million.

       Cumulative Effect of Accounting Change

           Results for 2003 include an after-tax credit to net income of $31.7
million recorded upon the adoption of SFAS 143 in January 2003. We identified
applicable legal obligations as defined under the new standard for nuclear power
plant decommissioning and reclamation of a sludge disposal pond at the Bruce
Mansfield Plant. As a result of adopting SFAS 143 in January 2003, asset
retirement costs of $133.7 million were recorded as part of the carrying amount
of the related long-lived asset, offset by accumulated depreciation of $25.2
million. The cumulative effect adjustment for unrecognized depreciation and
accretion, offset by the reduction in the existing decommissioning liabilities
and the reversal of accumulated estimated removal costs for non-regulated
generation assets, was a $54.1 million increase to income, or $31.7 million net
of income taxes.

Capital Resources and Liquidity
-------------------------------

           Our improving financial position reflects ongoing efforts to increase
competitiveness and enhance shareholder value. We have continued to strengthen
our financial position over the past five years by improving our fixed charge
coverage ratios. Our mortgage indenture ratio, which is used to measure our
ability to issue first mortgage bonds, increased from 6.21 in 1997 to 15.92 in
2003, which enhances our financial flexibility. Over the same period, our
charter ratio, a measure of our ability to issue preferred stock, improved from
2.35 to 4.68 and our common stockholder's equity as a percentage of
capitalization rose from approximately 48% at the end of 1997 to 66.9% at the
end of 2003. Over the last five years, we have reduced the average cost of
long-term debt from 7.77% in 1997 to 4.51% at the end of 2003.

       Changes in Cash Position

           As of December 31, 2003, we had $1.9 million of cash and cash
equivalents, compared with $20.5 million as of December 31, 2002. The major
sources for changes in these balances are summarized below.

       Cash Flows From Operating Activities

           Our consolidated net cash from operating activities is provided by
our regulated energy services. Net cash provided from operating activities was
$1.1 billion in 2003 and 2002 and $0.7 billion in 2001. Cash flows provided from
2003, 2002 and 2001 operating activities are as follows:

  Operating Cash Flows                    2003         2002         2001
  ----------------------------------------------------------------------
                                                   (In millions)

  Cash earnings (1)................     $  689       $  713         $743
  Working capital and other........        423          344          (75)
  -----------------------------------------------------------------------

  Total............................     $1,112       $1,057         $668
  ======================================================================

  (1) Includes net income, depreciation and amortization,
      deferred income taxes, investment tax credits and major noncash
      charges.

           Net cash provided from operating activities increased $55 million in
2003 compared to 2002 due to a $79 million reduction in working capital
requirements partially offset by a $24 million decrease from cash earnings. The
change in net use of working capital primarily represents increases in accounts
payable partially offset by decreased accounts receivable and higher tax
accruals in 2003.

       Cash Flows From Financing Activities

           In 2003 and 2002, the net cash used for financing activities of
$981.8 million and $598.6 million, respectively, primarily reflects the
redemptions of debt and the payment of common stock dividends to FirstEnergy.
The following table provides details regarding new issues and redemptions during
2003 and 2002:

                                        4

<PAGE>

Securities Issued or Redeemed                        2003         2002
----------------------------------------------------------------------
                                                       (In millions)
New Issues
         Pollution Control Notes...............     $  --         $ 15
         Unsecured Notes.......................       325           --
         Long-Term Revolving Credit............        40           --
----------------------------------------------------------------------
                                                    $ 365         $ 15
Redemptions
         First Mortgage Bonds..................     $ 410         $280
         Pollution Control Notes...............        30           15
         Secured Notes.........................        62          127
         Preferred Stock.......................         1          221
         Other, principally redemption premiums        17            4
----------------------------------------------------------------------
                                                    $ 520         $647

Short-term Borrowings, Net (use)/source of cash     $(225)        $162
----------------------------------------------------------------------


           We had approximately $368.4 million of cash and temporary investments
and approximately $182.9 million of short-term indebtedness at the end of 2003.
Available borrowing capability under bilateral bank facilities totaled $142
million as of December 31, 2003. The Company and its wholly owned utility
subsidiary, Pennsylvania Power Company (Penn), referred to as "Companies" had
the capability to issue $2.1 billion of additional first mortgage bonds on the
basis of property additions and retired bonds, although unsecured senior note
indentures entered into by the Company in 2003 limit its ability to issue
secured debt, including FMBs, subject to certain exceptions. Based upon
applicable earnings coverage tests the Companies could issue a total of $2.6
billion of preferred stock (assuming no additional debt was issued) as of the
end of 2003.

           We have the ability to borrow from our regulated affiliates and
FirstEnergy to meet our short-term working capital requirements. FirstEnergy
Service Company administers this money pool and tracks surplus funds of
FirstEnergy and its regulated subsidiaries, as well as proceeds available from
bank borrowings. Available bank borrowings include $1.75 billion from
FirstEnergy's and the Company's revolving credit facilities. Companies receiving
a loan under the money pool agreements must repay the principal amount of such a
loan, together with accrued interest, within 364 days of borrowing the funds.
The rate of interest is the same for each company receiving a loan from the pool
and is based on the average cost of funds available through the pool. The
average interest rate for borrowings in 2003 was 1.47%.

           Our access to capital markets and costs of financing are dependent on
the ratings of our securities and that of our holding company, FirstEnergy. The
following table shows our securities' ratings following the downgrade by Moody's
Investors Service in February 2004. The ratings outlook on all securities is
stable.


Ratings of Securities
-------------------------------------------------------------------------
                    Securities           S&P       Moody's         Fitch
-------------------------------------------------------------------------
FirstEnergy       Senior unsecured       BB+         Baa3          BBB-

Ohio Edison       Senior secured         BBB         Baa1          BBB+
                  Senior unsecured       BB+         Baa2          BBB
                  Preferred stock        BB          Ba1           BBB-

Penn              Senior secured         BBB-        Baa1          BBB+
                  Senior unsecured (1)   BB+         Baa2          BBB
                  Preferred stock        BB          Ba1           BBB-
-------------------------------------------------------------------------

(1) Penn's only senior unsecured debt obligations are pollution control revenue
    refunding bonds issued in the name of the Ohio Air Quality Development
    Authority to which this rating applies.


           On September 30, 2003, Fitch Ratings lowered the senior unsecured
ratings of FirstEnergy to "BBB-" from "BBB." Fitch affirmed the Companies'
ratings. Fitch announced that the Rating Outlook is Stable for the securities of
FirstEnergy, and all of the securities of its electric utility operating
companies. Fitch stated that the changes to the long-term ratings were "driven
by the high debt leverage of the parent, FirstEnergy. Despite management's
commitment to reduce debt related to the GPU merger, subsequent cash flows have
been vulnerable to unfavorable events, slowing the pace of FirstEnergy's debt
reduction efforts. The Stable Outlook reflects the success of FirstEnergy's
recent common equity offering and management's focus on a relatively
conservative integrated utility strategy."

                                        5
<PAGE>

           On December 23, 2003,  Standard & Poor's (S&P)  lowered its corporate
credit ratings on FirstEnergy and its regulated  utility  subsidiaries to "BBB-"
from "BBB" and lowered  FirstEnergy's senior unsecured debt rating to "BB+" from
"BBB-".  Except for OE's senior secured issue rating,  which was left unchanged,
all other  subsidiary  ratings were lowered one notch as well.  The ratings were
removed from CreditWatch with negative implications,  where they had been placed
by S&P on August 18,  2003,  and the Ratings  Outlook  returned  to Stable.  The
rating  action  followed  a revision  in S&P's  assessment  of our  consolidated
business  risk  profile to `6' from `5' (`1'  equals low risk,  `10' equals high
risk),  with  S&P  citing  operational  and  management  challenges  as  well as
heightened  regulatory  uncertainty  for  its  revision  of  our  business  risk
assessment  score.  S&P's  rationale for its  revisions of the ratings  included
uncertainty  regarding  the timing of the Ohio Rate Plan filing (see  Regulatory
Matters),  the  pending  final  report on the August  14th  blackout  (see Power
Outage),  the outcome of the remedial phase of litigation relating to the Sammis
plant (see  Environmental  Matters),  and the extended  Davis-Besse  outage (the
Companies have no ownership  interest in  Davis-Besse)  and the related  pending
subpoena.  S&P further stated that the restart of  Davis-Besse  and a supportive
Ohio Rate Plan extension will be vital positive  developments  that would aid an
upgrade of  FirstEnergy's  ratings.  S&P's  reduction  of the credit  ratings in
December  2003  triggered  cash  and   letter-of-credit   collateral   calls  of
FirstEnergy  in  addition  to  higher   interest  rates  for  some   outstanding
borrowings.

           On February 6, 2004, Moody's downgraded FirstEnergy senior unsecured
debt to Baa3 from Baa2. The ratings of OE and Penn were confirmed. Moody's said
that the lower ratings were prompted by: "1) high consolidated leverage with
significant holding company debt, 2) a degree of regulatory uncertainty in the
service territories in which the company operates, 3) risks associated with
investigations of the causes of the August 2003 blackout, and related securities
litigation, and 4) a narrowing of the ratings range for the FirstEnergy
operating utilities, given the degree to which FirstEnergy increasingly manages
the utilities as a single system and the significant financial interrelationship
among the subsidiaries."

       Cash Flows From Investing Activities

           Net cash flows used in investing activities totaled $148 million in
2003 and $443 million in 2002. These net cash flows used for investing resulted
from property additions for both years and notes to associated companies for
2002, which were offset in part by a reduction of the PNBV Capital Trust
investment. Expenditures for property additions primarily include expenditures
supporting our distribution of electricity.

           Our cash requirements in 2004 for operating expenses, construction
expenditures, scheduled debt maturities and preferred stock redemptions are
expected to be met without increasing our net debt and preferred stock
outstanding. Available borrowing capacity under short-term credit facilities
will be used to manage working capital requirements. Over the next three years,
we expect to meet our contractual obligations with cash from operations.
Thereafter, we expect to use a combination of cash from operations and funds
from the capital markets.

           Our capital spending for the period 2004-2006 is expected to be about
$438 million (excluding nuclear fuel) of which approximately $174 million
applies to 2004. Investments for additional nuclear fuel during the 2004-2006
period are estimated to be approximately $82 million, of which approximately $48
million relates to 2004. During the same periods, our nuclear fuel investments
are expected to be reduced by approximately $85 million and $43 million,
respectively, as the nuclear fuel is consumed.

Contractual Obligations
-----------------------

           Our cash contractual obligations as of December 31, 2003 that we
consider firm obligations are as follows:

<TABLE>
<CAPTION>

                                                                       2005-            2007-
Contractual Obligations               Total            2004            2006             2008          Thereafter
----------------------------------------------------------------------------------------------------------------
                                                                  (In millions)
<S>                                  <C>               <C>             <C>              <C>             <C>
Long-term debt...................    $1,639            $123            $182             $185            $1,149
Short-term borrowings............       183             183              --               --                --
Preferred stock (1)..............        14               1               2               11                --
Capital leases (2)...............        15               4               9                1                 1
Operating leases (2).............     1,237              79             163              184               811
Purchases (3)....................       289              47              82               63                97
--------------------------------------------------------------------------------------------------------------
     Total.......................    $3,377            $437            $438             $444            $2,058
--------------------------------------------------------------------------------------------------------------

<FN>

(1) Subject to mandatory redemption.
(2) Operating lease payments are net of capital trust receipts of $591.0 million
    (see Note 2).
(3) Fuel and power purchases under contracts with fixed or minimum
    quantities and approximate timing.

</FN>
</TABLE>




<PAGE>


Off-Balance Sheet Arrangements
------------------------------

           Obligations not included on our Consolidated Balance Sheet primarily
consist of sale and leaseback arrangements involving Perry Unit 1 and Beaver
Valley Unit 2, which are reflected in the operating lease payments disclosed
above (see Note 2 - Leases). The present value of these sale and leaseback
operating lease commitments, net of trust investments, was $689 million as of
December 31, 2003.

Interest Rate Risk
------------------

           Our exposure to fluctuations in market interest rates is reduced
since a significant portion of our debt has fixed interest rates, as noted in
the following table which presents principal amounts and related weighted
average interest rates by year of maturity for our investment portfolio, debt
obligations and preferred stock with mandatory redemption provisions.


<TABLE>
<CAPTION>

Comparison of Carrying Value to Fair Value
-------------------------------------------------------------------------------------------------------------------
                                                                                        There-                Fair
Year of Maturity                  2004       2005       2006       2007       2008       after      Total     Value
-------------------------------------------------------------------------------------------------------------------
                                                                (Dollars in millions)
<S>                               <C>        <C>         <C>       <C>        <C>         <C>      <C>       <C>
Assets
Investments Other Than Cash
   and Cash Equivalents-
   Fixed Income...............    $308       $186        $37       $39        $ 17        $654     $1,241    $1,303
   Average interest rate......     7.8%       7.9%       8.1%      8.3%        8.2%        7.4%       7.6%
____________________________________________________________________________________________________________________
Liabilities
Long-term Debt and Other
  Long-Term Obligations:
Fixed rate....................    $123       $137        $ 5       $ 6        $179        $468     $  918    $  956
   Average interest rate .....     7.5%       7.2%       7.9%      7.9%        4.1%        6.0%       6.1%
Variable rate.................               $ 40                                         $681     $  721    $  721
   Average interest rate......                2.2%                                         2.3%       2.3%
Preferred Stock Subject to
   Mandatory Redemption.......    $  1       $  1        $ 1       $11                             $   14    $   14
   Average dividend rate......     7.6%       7.6%       7.6%      7.6%                               7.6%
Short-term Borrowings.........    $183                                                             $  183    $  183
   Average interest rate......     1.2%                                                               1.2%
-------------------------------------------------------------------------------------------------------------------

</TABLE>


Equity Price Risk
-----------------

           Included in our nuclear decommissioning trust investments are
marketable equity securities carried at their market value of approximately $209
million and $148 million as of December 31, 2003 and 2002, respectively. A
hypothetical 10% decrease in prices quoted by stock exchanges would result in a
$21 million reduction in fair value as of December 31, 2003 (see Note 1(L) -
Cash and Financial Instruments).

Outlook
-------

           Our industry continues to transition to a more competitive
environment. In 2001, all our customers could select alternative energy
suppliers. We continue to deliver power to residential homes and businesses
through our existing distribution systems, which remain regulated. Customer
rates have been restructured into separate components to support customer
choice. In Ohio and Pennsylvania, we have a continuing responsibility to provide
power to those customers not choosing to receive power from an alternative
energy supplier subject to certain limits. Adopting new approaches to regulation
and experiencing new forms of competition have created new uncertainties.

       Regulatory Matters

       Ohio-

           Beginning on January 1, 2001, Ohio customers were able to choose
their electricity suppliers. Ohio customer rates were restructured to establish
separate charges for transmission, distribution, transition cost recovery and a
generation-related component. When one of our Ohio customers elects to obtain
power from an alternative supplier, we reduce the customer's bill with a
"generation shopping credit," based on the regulated generation component (plus
an incentive for OE customers), and the customer receives a generation charge
from the alternative supplier. OE has continuing PLR responsibility to its
franchise customers through December 31, 2005. Regulatory assets are costs which
have been authorized by the Public Utilities Commission of Ohio (PUCO), the
Pennsylvania Public Utility Commission (PPUC) and the Federal Energy Regulatory
Commission (FERC) for recovery from customers in future periods and, without
such authorization, would have been charged to income when incurred. All of our
regulatory assets are expected


                                       7
<PAGE>




to continue to be recovered under the provisions of our transition plan as
discussed below. Our regulatory assets are as follows:


Regulatory Assets as of December 31,
---------------------------------------------------------
Company                           2003             2002
---------------------------------------------------------
                                      (In millions)
Ohio Edison................     $1,450            $1,787
Penn.......................         28               151
--------------------------------------------------------
   Consolidated Total......     $1,478            $1,938
========================================================


           As part of our Ohio transition plan, we are obligated to supply
electricity to customers who do not choose an alternative supplier. The Company
is also required to provide 560 megawatts (MW) of low cost supply to
unaffiliated alternative suppliers who serve customers within its service area.
Our competitive retail sales affiliate, FES, acts as an alternate supplier for a
portion of the load in its franchise area.

           On October 21, 2003, FirstEnergy's Ohio regulated subsidiaries filed
an application with the PUCO to establish generation service rates beginning
January 1, 2006, in response to expressed concerns by the PUCO about price and
supply uncertainty following the end of the market development period. The
filing included two options:

        o  A competitive auction, which would establish a price for generation
           that customers would be charged during the period covered by the
           auction, or

        o  A Rate Stabilization Plan, which would extend current generation
           prices through 2008, ensuring adequate generation supply at stable
           prices, and continuing our support of energy efficiency and economic
           development efforts.

           Under the first option, an auction would be conducted to secure
generation service for our Ohio customers. Beginning in 2006, customers would
pay market prices for generation as determined by the auction.

           Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of our support of energy-efficiency programs and the potential for
continuing the program to give preferred access to nonaffiliated entities to
generation capacity if shopping drops below 20%. Under the proposed plan, we are
requesting:

        o  Extension of the transition cost amortization period from 2006 to
           2007;

        o  Deferral  of  interest  costs  on the  accumulated  shopping
           incentives  and  other  cost  deferrals  as new regulatory assets;
           and

        o  Ability to initiate a request to increase generation rates under
           certain limited conditions.

           On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
23, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. A decision is expected from the
PUCO in the Spring of 2004.

           On November 25, 2003, the PUCO ordered FirstEnergy to file a plan
with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will
address certain problems identified by the U.S.-Canada Power System Outage Task
Force (in connection with the August 14, 2003 regional power outage) and
addressing how FirstEnergy proposes to upgrade its control room computer
hardware and software, improve its control room training procedures and improve
the training of control room operators to ensure that similar problems do not
occur in the future. The PUCO, in consultation with the North American Electric
Reliability Council, will review the plan before determining the next steps in
the proceeding.

     Pennsylvania-

           In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the Tentative Order nor the Reliability
Rulemaking has been finalized, the PPUC ordered all Pennsylvania utilities to
begin filing quarterly reports on November 1, 2003. The comment period for both
the Tentative Order and the Proposed

                                        8
<PAGE>




Rulemaking Order has closed. We are currently awaiting the PPUC to issue a final
order in both matters. The order will determine (1) the standards and benchmarks
to be utilized, and (2) the details required in the quarterly and annual
reports. It is expected that these Orders will be finalized in March 2004.

           On January 16, 2004, the PPUC initiated a formal investigation of and
Penn's levels of compliance with the Public Utility Code and the PPUC's
regulations and orders with regard to reliable electric service. Hearings will
be held in August in this investigation and the ALJ has been directed to issue a
Recommended Decision by September 30, 2004, in order to allow the PPUC time to
issue a Final Order before December 16, 2004. We are unable to predict the
outcome of the investigation or the impact of the PPUC Order.

       Environmental Matters

           We believe we are in material compliance with current sulfur dioxide
(SO2) and nitrogen oxide (NOx) reduction requirements under the Clean Air Act
Amendments of 1990. In 1998, the Environmental Protection Agency (EPA) finalized
regulations requiring additional NOx reductions from the Companies' Ohio and
Pennsylvania facilities. Various regulatory and judicial actions have since
sought to further define NOx reduction requirements. We continue to evaluate our
compliance plans and other compliance options.

           Violations of federally approved SO2 regulations can result in
shutdown of the generating unit involved and/or civil or criminal penalties of
up to $31,500 for each day the unit is in violation. The EPA has an interim
enforcement policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.

           In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against the Companies in the U.S. District Court for the Southern District of
Ohio. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the W. H. Sammis Plant dating back to 1984. The
complaint requests permanent injunctive relief to require the installation of
"best available control technology" and civil penalties of up to $27,500 per day
of violation. On August 7, 2003, the United States District Court for the
Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis
Plant between 1984 and 1998 required pre-construction permits under the Clean
Air Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact, and employment consequences. The Court may also
consider the less than consistent efforts of the EPA to apply and further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the capital expenditures necessary to comply with substantive remedial
measures that may be required, could have a material adverse impact on the
Company's financial condition and results of operations. Management is unable to
predict the ultimate outcome of this matter and no liability has been accrued as
of December 31, 2003.

           As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA subsequently determined that regulation of coal ash as a
hazardous waste is unnecessary. In April 2000, the EPA announced that it will
develop national standards regulating disposal of coal ash under its authority
to regulate nonhazardous waste.

           In December 1997, delegates to the United Nations' climate summit in
Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global
warming by reducing the amount of man-made greenhouse gases emitted by developed
countries by 5.2% from 1990 levels between 2008 and 2012. The United States
signed the Protocol in 1998 but failed to receive the two-thirds vote of the
U.S. Senate required for ratification. However, the Bush administration has
committed the United States to a voluntary climate change strategy to reduce
domestic greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through 2012.

           We cannot currently estimate the financial impact of climate change
policies although the potential restrictions on carbon dioxide (CO2) emissions
could require significant capital and other expenditures. However, the CO2
emissions per kilowatt-hour of electricity generated by the Companies are lower
than many regional competitors due to our diversified generation sources which
includes the low or non-CO2 emitting gas-fired and nuclear generators.

                                      9
<PAGE>


       Power Outage

           On August 14, 2003, various states in the northeast United States and
southern Canada experienced a widespread power outage. That outage affected
approximately 1.4 million customers in FirstEnergy's service area. FirstEnergy
continues to accumulate data and evaluate the status of its electrical system
prior to and during the outage event, and continues to cooperate with the
U.S.-Canada Power System Outage Task Force (Task Force) investigating the August
14th outage. The interim report issued by the Task Force on November 18, 2003
concluded that the problems leading up to the outage began in FirstEnergy's
service area. Specifically, the interim report concludes, among other things,
that the initiation of the August 14th outage resulted from the coincidence on
that afternoon of the following events: (1) inadequate situational awareness at
FirstEnergy; (2) FirstEnergy's failure to adequately manage tree growth in its
transmission rights of way; and (3) failure of the interconnected grid's
reliability organizations (Midwest ISO and PJM Interconnection) to provide
effective diagnostic support. We believe that the interim report does not
provide a complete and comprehensive picture of the conditions that contributed
to the August 14th outage and that it does not adequately address the underlying
causes of the outage. We remain convinced that the outage cannot be explained by
events on any one utility's system. On November 25, 2003, the PUCO ordered
FirstEnergy to file a plan with the PUCO no later than March 1, 2004,
illustrating how FirstEnergy will correct problems identified by the Task Force
as events contributing to the August 14th outage and addressing how FirstEnergy
proposes to upgrade its control room computer hardware and software and improve
the training of control room operators to ensure that similar problems do not
occur in the future. The PUCO, in consultation with the North American Electric
Reliability Council, will review the plan before determining the next steps in
the proceeding. On December 24, 2003, the Federal Energy Regulatory Commission
(FERC) ordered FirstEnergy to pay for an independent study of part of Ohio's
power grid. The study has commenced and will examine the stability of the grid
in critical points in the Cleveland and Akron areas; the status of projected
power reserves during summer 2004 through 2008; and the need for new
transmission lines or other grid projects. The FERC ordered the study to be
completed within 120 days. At this time, we do not know how the results of the
study will impact FirstEnergy.

       Legal Matters

           Various lawsuits, claims and proceedings related to our normal
business operations are pending against us, the most significant of which are
described above.

Critical Accounting Policies
----------------------------

       Significant Accounting Policies

           We prepare our consolidated financial statements in accordance with
accounting principles that are generally accepted in the United States (GAAP).
Application of these principles often requires a high degree of judgment,
estimates and assumptions that affect financial results. All of our assets are
subject to their own specific risks and uncertainties and are regularly reviewed
for impairment. Assets related to the application of the policies discussed
below are similarly reviewed with their risks and uncertainties reflecting these
specific factors. Our more significant accounting policies are described below.

       Regulatory Accounting

           We are subject to regulation that sets the prices (rates) we are
permitted to charge our customers based on the costs that the regulatory
agencies determine we are permitted to recover. At times, regulators permit the
future recovery through rates of costs that would be currently charged to
expense by an unregulated company. This rate-making process results in the
recording of regulatory assets based on anticipated future cash inflows. As a
result of the changing regulatory framework in Ohio and Pennsylvania, a
significant amount of regulatory assets have been recorded - $1.5 billion as of
December 31, 2003. We regularly review these assets to assess their ultimate
recoverability within the approved regulatory guidelines. Impairment risk
associated with these assets relates to potentially adverse legislative,
judicial or regulatory actions in the future.

       Revenue Recognition

           We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hours that have been delivered but not yet billed through
the end of the accounting period. The determination of unbilled revenues
requires management to make various estimates including:

        o  Net energy generated or purchased for retail load
        o  Losses of energy over distribution lines
        o  Allocations to distribution companies within the FirstEnergy system
        o  Mix of kilowatt-hour usage by residential, commercial and
           industrial customers
        o  Kilowatt-hour usage of customers receiving electricity from
           alternative suppliers

                                     10
<PAGE>


       Pension and Other Postretirement Benefits Accounting

           FirstEnergy's reported costs of providing non-contributory defined
pension benefits and postemployment benefits other than pensions are dependent
upon numerous factors resulting from actual plan experience and certain
assumptions.

           Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions FirstEnergy makes to the plans, and earnings on plan assets. Such
factors may be further affected by business combinations (such as FirstEnergy's
merger with GPU, Inc. in November 2001), which impacts employee demographics,
plan experience and other factors. Pension and OPEB costs are also affected by
changes to key assumptions, including anticipated rates of return on plan
assets, the discount rates and health care trend rates used in determining the
projected benefit obligations for pension and OPEB costs.

           Plan amendments to retirement health care benefits in 2003 and 2002,
related to changes in benefits provided and cost-sharing provisions, reduced
FirstEnergy's obligation by $123 and $121 million, respectively. In early 2004,
FirstEnergy announced that it would amend the benefit provisions of its health
care benefits plan and both employees and retirees would share in more of the
benefit costs.

           In accordance with SFAS 87, "Employers' Accounting for Pensions" and
SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," changes in pension and OPEB obligations associated with these factors
may not be immediately recognized as costs on the income statement, but
generally are recognized in future years over the remaining average service
period of plan participants. SFAS 87 and SFAS 106 delay recognition of changes
due to the long-term nature of pension and OPEB obligations and the varying
market conditions likely to occur over long periods of time. As such,
significant portions of pension and OPEB costs recorded in any period may not
reflect the actual level of cash benefits provided to plan participants and are
significantly influenced by assumptions about future market conditions and plan
participants' experience.

           In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. Due to recent declines in corporate bond
yields and interest rates in general, FirstEnergy reduced the assumed discount
rate as of December 31, 2003 to 6.25% from 6.75% and 7.25% used as of December
31, 2002 and 2001, respectively.

           FirstEnergy's assumed rate of return on pension plan assets considers
historical market returns and economic forecasts for the types of investments
held by their pension trusts. In 2003, 2002 and 2001, plan assets actually
earned 24.0%, (11.3)% and (5.5)%, respectively. FirstEnergy's pension costs in
2003 were computed assuming a 9.0% rate of return on plan assets based upon
projections of future returns and their pension trust investment allocation of
approximately 70% equities, 27% bonds, 2% real estate and 1% cash.

           As a result of GPU Service Inc. merging with FirstEnergy Service
Company in the second quarter of 2003, operating company employees of GPU
Service were transferred to the former GPU operating companies. Accordingly,
FirstEnergy requested an actuarial study to update the pension liabilities for
each of its subsidiaries. Based on the actuary's report, our accrued pension
costs as of June 30, 2003 increased by $67 million. The corresponding adjustment
related to this change decreased other comprehensive income and deferred income
taxes and increased the payable to associated companies.

           Due to the increased market value of our pension plan assets,
we reduced our minimum liability as prescribed by SFAS 87 as of December 31,
2003 by $85 million, recording an increase of $5 million in an intangible asset
and crediting OCI by $53 million (offsetting previously recorded deferred tax
benefits by $37 million). The remaining balance in OCI of $62 million will
reverse in future periods to the extent the fair value of trust assets exceeds
the accumulated benefit obligation. The accrued pension cost was reduced to $81
million as of December 31, 2003.

           Based on pension assumptions and pension plan assets as of December
31, 2003, FirstEnergy will not be required to fund their pension plans in 2004.
However, health care cost trends have significantly increased and will affect
future OPEB costs. FirstEnergy's pension and OPEB expenses in 2004 are expected
to decrease by $38 million and $34 million, respectively. These reductions
reflect the actual performance of pension plan assets and amendments to the
health care benefits plan announced in early 2004 which result in employees and
retirees sharing more of the benefit costs. The reduction in OPEB costs for 2004
does not reflect the impact of the new Medicare law signed by President Bush in
December 2003 due to uncertainties regarding some of its new provisions (see
Note 1(J)). The 2003 and 2002 composite health care trend rate assumptions are
approximately 10%-12% gradually decreasing to 5% in later years. In determining
their trend rate assumptions, FirstEnergy included the specific provisions of
their health care plans, the demographics and utilization rates of plan
participants, actual cost increases experienced in their health care plans, and
projections of future medical trend rates. The effect on FirstEnergy's pension
and OPEB costs and liabilities from changes in key assumptions are as follows:
<TABLE>
<CAPTION>


Increase in Costs from Adverse Changes in Key Assumptions
------------------------------------------------------------------------------------------------
Assumption                       Adverse Change              Pension         OPEB        Total
------------------------------------------------------------------------------------------------
                                                                          (In millions)
<S>                              <C>                          <C>             <C>         <C>
Discount rate................    Decrease by 0.25%            $ 10            $ 5         $ 15
Long-term return on assets...    Decrease by 0.25%            $  8            $ 1         $  9
Health care trend rate.......    Increase by 1%                 na            $26         $ 26

Increase in Minimum Liability
-----------------------------
Discount rate................    Decrease by 0.25%            $104             na         $104
----------------------------------------------------------------------------------------------

</TABLE>


       Ohio Transition Cost Amortization

           In connection with our Ohio transition plan, the PUCO determined
allowable transition costs based on amounts recorded on the regulatory books of
the Ohio electric utilities. These costs exceeded those deferred or capitalized
on the Company's balance sheet prepared under GAAP since they included certain
costs which have not yet been incurred. We use an effective interest method for
amortizing its transition costs, often referred to as a "mortgage-style"
amortization. The interest rate under this method is equal to the rate of return
authorized by the PUCO in the transition plan for each respective company. In
computing the transition cost amortization, we include only the portion of the
transition revenues associated with transition costs included on the balance
sheet prepared under GAAP. Revenues collected for the off balance sheet costs
and the return associated with these costs are recognized as income when
received.

       Long-Lived Assets

           In accordance with SFAS 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets," we periodically evaluate our long-lived assets
to determine whether conditions exist that would indicate that the carrying
value of an asset might not be fully recoverable. The accounting standard
requires that if the sum of future cash flows (undiscounted) expected to result
from an asset is less than the carrying value of the asset, an asset impairment
must be recognized in the financial statements. If impairment has occurred, we
recognize a loss - calculated as the difference between the carrying value and
the estimated fair value of the asset (discounted future net cash flows).

           The calculation of future cash flows is based on assumptions,
estimates and judgement about future events. The aggregate amount of cash flows
determines whether an impairment is indicated. The timing of the cash flows is
critical in determining the amount of the impairment.

       Nuclear Decommissioning

           In accordance with SFAS 143, we recognize ARO for the future
decommissioning of our nuclear power plants. The ARO liability represents an
estimate of the fair value of our current obligation related to nuclear
decommissioning and the retirement of other assets. A fair value measurement
inherently involves uncertainty in the amount and timing of settlement of the
liability. We used an expected cash flow approach (as discussed in FASB Concepts
Statement No. 7, "Using Cash Flow Information and Present Value in Accounting
Measurements") to measure the fair value of the nuclear decommissioning ARO.
This approach applies probability weighting to discounted future cash flow
scenarios that reflect a range of possible outcomes. The scenarios consider
settlement of the ARO at the expiration of the nuclear power plants' current
license and settlement based on an extended license term.

New Accounting Standards and Interpretations Adopted
----------------------------------------------------

       FIN 46 (revised December 2003), "Consolidation of Variable Interest
       Entities"

           In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities", referred
to as "FIN 46R", requires the consolidation of a VIE by an enterprise if that
enterprise is determined to be the primary beneficiary of the VIE. As required,
we adopted FIN 46R for interests in VIEs or potential VIEs commonly referred to
as special-purpose entities effective December 31, 2003. We will adopt FIN 46R
for all other types of entities effective March 31, 2004.

           We currently have transactions with entities in connection with sale
and leaseback arrangements which fall within the scope of this interpretation
and which meet the definition of a VIE in accordance with FIN 46R. Upon adoption
of FIN 46R effective December 31, 2003, we consolidated the PNBV Capital Trust
(PNBV) which was created in 1996 to refinance debt in connection with sale and
leaseback transactions. Consolidation of PNBV changed the trust investment of
$361 million to an investment in collateralized lease bonds of $372 million. The
$11 million increase represents the minority interest in the total assets of the
trust.

           In reviewing the sale and leaseback arrangements, the Company also
evaluated its interest in the owner trusts that acquired interests in the Perry
Plant and Beaver Valley Unit 2. The Company was determined not to be the primary
beneficiary of any of these owner trusts and was therefore not required to
consolidate these entities. The leases are accounted for as operating leases in
accordance with GAAP and their related obligations are disclosed in Note 2.

       SFAS 150, "Accounting for Certain Financial Instruments with
       Characteristics of both Liabilities and Equity"

           In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,

                                        12

<PAGE>

certain financial instruments that embody obligations for the issuer are
required to be classified as liabilities. SFAS 150 was effective immediately for
financial instruments entered into or modified after May 31, 2003 and effective
at the beginning of the first interim period beginning after June 15, 2003 for
all other financial instruments.

           Upon adoption of SFAS 150, effective July 1, 2003, we reclassified as
debt the preferred stock of consolidated subsidiaries subject to mandatory
redemption with a carrying value of approximately $14 million as of December 31,
2003. Prior to the adoption of SFAS 150, subsidiary preferred dividends on our
Consolidated Statements of Income were included in net interest charges.
Therefore, the application of SFAS 150 did not require the reclassification of
such preferred dividends to net interest charges.

       SFAS 143, "Accounting for Asset Retirement Obligations"

           In January 2003, we implemented SFAS 143 which provides accounting
standards for retirement obligations associated with tangible long-lived assets.
This statement requires recognition of the fair value of a liability for an
asset retirement obligation in the period in which it is incurred. See Notes
1(F) and 1(I) for further discussions of SFAS 143.

       EITF  Issue  No.  03-1,  "The  Meaning  of  Other-Than-Temporary
       Impairment  and its  Application  to  Certain Investments"

           In November 2003, the EITF reached consensus that certain
quantitative and qualitative disclosures are required for debt and equity
securities classified as available-for-sale or held-to-maturity. The guidance
requires the disclosure of the aggregate amount of unrealized losses and the
aggregate related fair value for investments with unrealized losses that have
not been recognized as other-than-temporary impairments. We adopted the
disclosure requirements of EITF Issue No. 03-1 as of December 31, 2003 (See Note
7(C)).

                                         13

<PAGE>



<TABLE>
<CAPTION>



                                                        OHIO EDISON COMPANY

                                                 CONSOLIDATED STATEMENTS OF INCOME


For the Years Ended December 31,                                                 2003         2002         2001
------------------------------------------------------------------------------------------------------------------
                                                                                          (In thousands)

<S>                                                                          <C>          <C>           <C>
OPERATING REVENUES (Note 1(K))..........................................     $2,925,832   $2,948,675    $3,056,464
                                                                             ----------   ----------    ----------

OPERATING EXPENSES AND TAXES:
   Fuel and purchased power (Note 1(K)).................................        966,892      986,737     1,096,317
   Nuclear operating costs..............................................        432,315      352,129       381,047
   Other operating costs (Note 1(K))....................................        365,720      364,436       313,177
                                                                             ----------   ----------    ----------
     Total operation and maintenance expenses...........................      1,764,927    1,703,302     1,790,541
   Provision for depreciation and amortization..........................        438,121      385,520       424,920
   General taxes........................................................        170,078      177,021       153,506
   Income taxes.........................................................        216,979      229,001       220,678
                                                                             ----------   ----------    ----------
     Total operating expenses and taxes.................................      2,590,105    2,494,844     2,589,645
                                                                             ----------   ----------    ----------

OPERATING INCOME........................................................        335,727      453,831       466,819

OTHER INCOME (Note 1(K))................................................         67,991       42,859        68,681
                                                                             ----------   ----------    ----------

INCOME BEFORE NET INTEREST CHARGES......................................        403,718      496,690       535,500
                                                                             ----------   ----------    ----------

NET INTEREST CHARGES:
   Interest on long-term debt...........................................         91,068      119,123       150,632
   Allowance for borrowed funds used during
     construction and capitalized interest..............................         (6,075)      (3,639)       (2,602)
   Other interest expense...............................................         22,069       14,598        22,754
   Subsidiaries' preferred stock dividend requirements..................          3,731       10,449        14,504
                                                                             ----------   ----------    ----------
     Net interest charges...............................................        110,793      140,531       185,288
                                                                             ----------   ----------    ----------

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE....................        292,925      356,159       350,212
   Cumulative effect of accounting change (net of income taxes of
     $22,389,000) (Note 1(I))...........................................         31,720           --            --
                                                                             ----------   ----------    ----------

NET INCOME..............................................................        324,645      356,159       350,212

PREFERRED STOCK DIVIDEND REQUIREMENTS...................................          2,732        6,510        10,702
                                                                             ----------   ----------    ----------

EARNINGS ON COMMON STOCK................................................     $  321,913   $  349,649    $  339,510
                                                                             ==========   ==========    ==========

<FN>


The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

</FN>
</TABLE>

                                                      14
<PAGE>

<TABLE>
<CAPTION>



                                                        OHIO EDISON COMPANY

                                                    CONSOLIDATED BALANCE SHEETS

As of December 31,                                                                        2003             2002
------------------------------------------------------------------------------------------------------------------
                                                                                             (In thousands)
                                        ASSETS
<S>                                                                                    <C>              <C>
UTILITY PLANT:
   In service......................................................................    $5,269,042       $4,989,056
   Less-Accumulated provision for depreciation.....................................     2,578,899        2,484,162
                                                                                       ----------       ----------
                                                                                        2,690,143        2,504,894
                                                                                       ----------       ----------
   Construction work in progress-
     Electric plant................................................................       145,380          122,741
     Nuclear Fuel..................................................................           554           23,481
                                                                                       ----------       ----------
                                                                                          145,934          146,222
                                                                                       ----------       ----------
                                                                                        2,836,077        2,651,116
                                                                                       ----------       ----------
OTHER PROPERTY AND INVESTMENTS:
   Investments in lease obligation bonds (Note 2)..................................       383,510          402,565
   Letter of credit collateralization (Note 2).....................................       277,763          277,763
   Nuclear plant decommissioning trusts............................................       376,367          293,190
   Long-term notes receivable from associated companies (Note 3(B).................       508,594          503,827
   Other...........................................................................        59,102           74,220
                                                                                       ----------       ----------
                                                                                        1,605,336        1,551,565
                                                                                       ----------       ----------
CURRENT ASSETS:
   Cash and cash equivalents.......................................................         1,883           20,512
   Receivables-
     Customers (less accumulated provisions of $8,747,000 and $5,240,000,
       respectively, for uncollectible accounts)...................................       280,538          296,548
     Associated companies..........................................................       436,991          592,218
     Other (less accumulated provision of  $2,282,000 and $1,000,000 for
       uncollectible accounts).....................................................        28,308           30,057
   Notes receivable from associated companies......................................       366,501          437,669
   Materials and supplies, at average cost-
     Owned.........................................................................        79,813           58,022
     Under consignment.............................................................            --           19,753
   Prepayments and other...........................................................        14,390           11,804
                                                                                       ----------       ----------
                                                                                        1,208,424        1,466,583
                                                                                       ----------       ----------
DEFERRED CHARGES:
   Regulatory assets...............................................................     1,477,969        1,937,709
   Property taxes..................................................................        59,279           59,035
   Unamortized sale and leaseback costs............................................        65,631           72,294
   Other...........................................................................        64,214           51,739
                                                                                       ----------       ----------
                                                                                        1,667,093        2,120,777
                                                                                       ----------       ----------
                                                                                       $7,316,930       $7,790,041
                                                                                       ==========       ==========
                           CAPITALIZATION AND LIABILITIES

CAPITALIZATION (See Consolidated Statements of Capitalization):
   Common stockholder's equity.....................................................    $2,582,970       $2,839,255
   Preferred stock not subject to mandatory redemption.............................        60,965           60,965
   Preferred stock of consolidated subsidiary-
     Not subject to mandatory redemption...........................................        39,105           39,105
     Subject to mandatory redemption (Note 3(F))...................................            --           13,500
   Long-term debt and other long-term obligations -
     Preferred stock of consolidated subsidiary subject to mandatory
       redemption (Note 3(F)) .....................................................        12,750               --
     Other.........................................................................     1,167,039        1,219,347
                                                                                       ----------       ----------
                                                                                        3,862,829        4,172,172
                                                                                       ----------       ----------
CURRENT LIABILITIES:
   Currently payable long-term debt and preferred stock............................       466,589          563,267
   Short-term borrowings -
     Associated companies..........................................................        11,334          225,345
     Other.........................................................................       171,540          182,317
   Accounts payable-
     Associated companies..........................................................       271,262          145,981
     Other.........................................................................         7,979           18,015
   Accrued taxes...................................................................       560,345          466,064
   Accrued interest................................................................        18,714           28,209
   Other...........................................................................        58,680           74,562
                                                                                       ----------       ----------
                                                                                        1,566,443        1,703,760
                                                                                       ----------       ----------
NONCURRENT LIABILITIES:
   Accumulated deferred income taxes...............................................       867,691        1,017,629
   Accumulated deferred investment tax credits.....................................        75,820           88,449
   Asset retirement obligation.....................................................       317,702               --
   Nuclear plant decommissioning costs.............................................            --          280,858
   Retirement benefits.............................................................       331,829          247,531
   Other...........................................................................       294,616          279,642
                                                                                       ----------       ----------
                                                                                        1,887,658        1,914,109
                                                                                       ----------       ----------
COMMITMENTS AND CONTINGENCIES (Notes 2 and 5)......................................
                                                                                       ----------       ----------
                                                                                       $7,316,930       $7,790,041
                                                                                       ==========       ==========


<FN>

The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets.

</FN>
</TABLE>
                                                     15

<PAGE>

<TABLE>
<CAPTION>


                                                        OHIO EDISON COMPANY

                                             CONSOLIDATED STATEMENTS OF CAPITALIZATION


As of December 31,                                                                              2003        2002
-------------------------------------------------------------------------------------------------------------------
                                            (Dollars in thousands, except per share amounts)
<S>                                                                                          <C>         <C>
COMMON STOCKHOLDER'S EQUITY:
   Common stock, without par value, authorized 175,000,000 shares-100 shares
     outstanding ...................................................................         $2,098,729  $2,098,729
   Accumulated other comprehensive loss (Note 3(G)).................................            (38,693)    (59,495)
   Retained earnings (Note 3(A))....................................................            522,934     800,021
                                                                                             ----------  ----------
       Total common stockholder's equity............................................          2,582,970   2,839,255
                                                                                             ----------  ----------
<CAPTION>

                                                Number of Shares          Optional
                                                  Outstanding          Redemption Price
                                                ----------------     --------------------
                                                2003       2002      Per Share  Aggregate
                                                ----       ----      ---------  ---------
<S>                                            <C>        <C>         <C>        <C>
PREFERRED STOCK (Note 3(D)):
Cumulative, $100 par value-
Authorized 6,000,000 shares
   Not Subject to Mandatory Redemption:

     3.90%................................     152,510    152,510     $103.63    $15,804         15,251      15,251
     4.40%................................     176,280    176,280      108.00     19,038         17,628      17,628
     4.44%................................     136,560    136,560      103.50     14,134         13,656      13,656
     4.56%................................     144,300    144,300      103.38     14,917         14,430      14,430
                                               -------    -------                -------     ----------  ----------
       Total Not Subject to
         Mandatory Redemption.............     609,650    609,650                $63,893         60,965      60,965
                                               =======    =======                =======     ----------  ----------

PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARY (Note 3(D)):
Pennsylvania Power Company-
Cumulative, $100 par value-
Authorized 1,200,000 shares
   Not Subject to Mandatory Redemption:
     4.24%................................      40,000     40,000     $103.13    $ 4,125          4,000       4,000
     4.25%................................      41,049     41,049      105.00      4,310          4,105       4,105
     4.64%................................      60,000     60,000      102.98      6,179          6,000       6,000
     7.75%................................     250,000    250,000      100.00     25,000         25,000      25,000
                                               -------    -------                -------     ----------  ----------

       Total Not Subject to Mandatory
         Redemption.......................     391,049    391,049                $39,614         39,105      39,105
                                               =======    =======                =======     ----------  ----------

   Subject to Mandatory Redemption (Note 3(F)):
     7.625%**.............................          --    142,500                                    --      14,250
     Redemption Within One Year**.........                                                                     (750)
                                               -------    -------                            ----------  ----------
       Total Subject to Mandatory Redemption        --    142,500                                    --      13,500
                                               =======    =======                            ----------  ----------


</TABLE>



                                                             16



<PAGE>


<TABLE>
<CAPTION>

                                                        OHIO EDISON COMPANY

                                        CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)

As of December 31,             2003     2002                             2003     2002          2003        2002
-----------------------------------------------------------------------------------------------------------------
                                                    (In thousands)
<S>                           <C>     <C>                               <C>      <C>            <C>         <C>
LONG-TERM DEBT (Note 3(E)):
First mortgage bonds:
   Ohio Edison Company-                       Pennsylvania Power Company-
     8.625% due 2003........      --  150,000   9.740% due 2004-2019.   15,617    16,591
     6.875% due 2005........  80,000   80,000   7.500% due 2003......       --    40,000
     8.750% due 2022........      --   50,960   6.375% due 2004......   20,500    20,500
     7.625% due 2023........      --   75,000   6.625% due 2004......   14,000    14,000
     7.875% due 2023........      --   93,500   8,500% due 2022......   27,250    27,250
                             -------  -------
                                                7.625% due 2023......    6,500     6,500
                                                                       -------   -------

Total first mortgage bonds..  80,000  449,460                           83,867   124,841        163,867     574,301
                             -------  -------                          -------   -------     ----------  ----------

Secured notes:
   Ohio Edison Company-                       Pennsylvania Power Company-
     7.680% due 2005........ 109,081  162,504   5.400% due 2013......    1,000     1,000
    *1.050% due 2015........  19,000   19,000   5.400% due 2017......   10,600    10,600
     6.750% due 2015........  40,000   40,000  *1.100% due 2017......   17,925    17,925
    *3.250% due 2015........  50,000       --   5.900% due 2018......   16,800    16,800
     7.050% due 2020........  60,000   60,000  *1.100% due 2021......   14,482    14,482
    *1.100% due 2021........     443      443   6.150% due 2023......   12,700    12,700
     5.375% due 2028........  13,522   13,522  *1.200% due 2027......   10,300    10,300
     5.625% due 2029........  50,000   50,000   5.375% due 2028......    1,734     1,734
     5.950% due 2029........  56,212   56,212   5.450% due 2028......    6,950     6,950
    *1.050% due 2030........  60,400   60,400   6.000% due 2028......   14,250    14,250
    *1.100% due 2031........  69,500   69,500   5.950% due 2029......      238       238
                                                                       -------   -------
    *1.100% due 2033........  57,100   57,100
     5.450% due 2033........  14,800   14,800
    *2.250% due 2033........  50,000       --
     Limited Partnerships-
     7.37% weighted average
       interest rate due
       2004-2010. ..........  21,432   29,513
                             -------  -------

Total secured notes......... 671,490  632,994                          106,979   106,979        778,469     739,973
                             -------  -------                          -------   -------     ----------  ----------

Unsecured notes:
   Ohio Edison Company-                       Pennsylvania Power Company-
    *2.238% due 2005........  40,000       --  *5.900% due 2033......    5,200     5,200
     4.000% due 2008........ 175,000       --  *2.500% due 2029......   14,500    14,500
                                                                       -------   -------
    *1.120% due 2014........  50,000   50,000
     5.450% due 2015........ 150,000       --
     4.850% due 2015........      --   50,000
    *5.800% due 2016........  47,725   47,725
    *1.340% due 2018........  33,000   33,000
    *1.300% due 2018........  23,000   23,000
    *1.300% due 2023........  50,000   50,000
     4.300% due 2033........      --   50,000
    *4.650% due 2033........ 108,000  108,000
     4.400% due 2033........      --   30,000
                             -------  -------

Total unsecured notes....... 676,725  441,725                           19,700    19,700        696,425     461,425
                             -------  -------                          -------   -------     ----------  ----------

Preferred stock subject to mandatory redemption**............................................    13,500          --
                                                                                             ----------  ----------
Capital lease obligations (Note 2)...........................................................     6,829       8,249
                                                                                             ----------  ----------
Net unamortized discount on debt.............................................................   (12,712)     (2,084)
                                                                                             ----------  ----------
Long-term debt due within one year**.........................................................  (466,589)   (562,517)
                                                                                             ----------  ----------
Total long-term debt and long-term obligations**............................................  1,179,789   1,219,347
                                                                                             ----------  ----------

TOTAL CAPITALIZATION........................................................................ $3,862,829  $4,172,172
                                                                                             ==========  ==========

<FN>


*  Denotes variable rate issue with December 31, 2003 interest rate shown.
** The December 31, 2003 balance for preferred stock subject to mandatory redemption is classified as debt under
   SFAS 150 (see Note 6).

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

</FN>
</TABLE>

                                                        17
<PAGE>

<TABLE>
<CAPTION>

                                                        OHIO EDISON COMPANY

                                      CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY



                                                                                             Accumulated
                                                                                               Other
                                                   Comprehensive     Number      Carrying   Comprehensive  Retained
                                                       Income       of Shares     Value     Income (Loss)  Earnings
                                                   -------------    ---------   --------    -------------  --------
                                                                            (Dollars in thousands)

<S>                                                   <C>              <C>      <C>           <C>          <C>
Balance, January 1, 2001.......................                        100      $2,098,729    $     --     $458,263
   Net income..................................       $350,212                                              350,212
                                                      ========
   Cash dividends on preferred stock...........                                                             (10,703)
   Cash dividends on common stock..............                                                            (225,500)
-------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001.....................                        100       2,098,729          --      572,272
   Net income..................................       $356,159                                              356,159
   Minimum liability for unfunded retirement
     benefits, net of $(45,525,000) of
     income taxes .............................        (64,585)                                (64,585)

   Unrealized gain on investments, net of
     $3,582,000 of income taxes................          5,090                                   5,090
                                                      --------
   Comprehensive income........................       $296,664
                                                      ========
   Cash dividends on preferred stock...........                                                              (6,510)
   Cash dividends on common stock..............                                                            (121,900)
-------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2002.....................                        100       2,098,729     (59,495)     800,021
   Net income..................................       $324,645                                              324,645
   Minimum liability for unfunded retirement
     benefits, net of $2,014,000 of
     income taxes .............................          2,674                                   2,674

   Unrealized gain on investments, net of
     $12,337,000 of income taxes...............         18,128                                  18,128
                                                      --------
   Comprehensive income........................       $345,447
                                                      ========
   Cash dividends on preferred stock...........                                                              (2,732)
   Cash dividends on common stock..............                                                            (599,000)
-------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2003.....................                        100      $2,098,729    $(38,693)    $522,934
===================================================================================================================


</TABLE>


<TABLE>
<CAPTION>



                                            CONSOLIDATED STATEMENTS OF PREFERRED STOCK

                                                         Not Subject to              Subject to
                                                      Mandatory Redemption        Mandatory Redemption
                                                      --------------------        --------------------
                                                       Number         Par          Number        Par
                                                      of Shares      Value        of Shares     Value
                                                      ---------      -----        ---------     -----
                                                                     (Dollars in thousands)

                  <S>                                <C>          <C>            <C>          <C>
                  Balance, January 1, 2001.........  5,000,699    $200,070       5,000,000    $ 140,000
                    Redemptions-
                      8.45%  Series................                                (50,000)      (5,000)
                  ------------------------------------------------------------------------------------
                  Balance, December 31, 2001.......  5,000,699     200,070       4,950,000      135,000
                    Redemptions -
                      7.75%  Series................ (4,000,000)   (100,000)
                      9.00%  Series................                             (4,800,000)    (120,000)
                      7.625% Series................                                 (7,500)        (750)
                  -------------------------------------------------------------------------------------
                  Balance, December 31, 2002.......  1,000,699     100,070         142,500       14,250
                    Redemptions -
                      7.625% Series................                                 (7,500)        (750)
                  -------------------------------------------------------------------------------------
                  Balance, December 31, 2003.......  1,000,699    $100,070         135,000    $  13,500*
                  =====================================================================================

<FN>

*  December 31, 2003 balance for preferred stock subject to mandatory redemption is classified as debt under
   SFAS 150 (see Note 6).

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

</FN>
</TABLE>

                                                          18
<PAGE>

<TABLE>
<CAPTION>


                                                        OHIO EDISON COMPANY

                                               CONSOLIDATED STATEMENTS OF CASH FLOWS


For the Years Ended December 31,                                                   2003         2002        2001
-------------------------------------------------------------------------------------------------------------------
                                                                                         (In thousands)
<S>                                                                             <C>          <C>          <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income...............................................................       $  324,645   $  356,159   $ 350,212
Adjustments to reconcile net income to net
   cash from operating activities:
     Provision for depreciation and amortization.........................          438,121      385,520     424,920
     Nuclear fuel and lease amortization.................................           39,317       47,597      45,417
     Cumulative effect of accounting change..............................          (54,109)          --          --
     Deferred income taxes, net..........................................          (73,541)     (61,987)    (63,945)
     Investment tax credits, net.........................................          (14,747)     (13,732)    (13,346)
     Receivables.........................................................          170,492      (41,584)    (61,246)
     Materials and supplies..............................................           (2,038)      (9,930)     64,177
     Accounts payable....................................................          132,983      182,229     (53,588)
     Other (Note 7)......................................................          150,499      212,929     (24,912)
                                                                                ----------   ----------   ---------
       Net cash provided from operating activities.......................        1,111,622    1,057,201     667,689
                                                                                ----------   ----------   ---------

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
   Long-term debt........................................................          365,000       14,500     111,584
   Short-term borrowings, net............................................               --      161,836          --
Redemptions and Repayments-
   Preferred stock.......................................................             (750)    (220,750)     (5,000)
   Long-term debt........................................................         (519,506)    (425,742)   (233,158)
   Short-term borrowings, net............................................         (224,788)          --     (69,606)
Dividend Payments-
   Common stock..........................................................         (599,000)    (121,900)   (225,500)
   Preferred stock.......................................................           (2,732)      (6,510)    (10,703)
                                                                                ----------   ----------   ---------
       Net cash used for financing activities............................         (981,776)    (598,566)   (432,383)
                                                                                ----------   ----------   ---------

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions.......................................................         (189,019)    (148,967)   (145,427)
Loan payments from (to) associated companies.............................           66,401     (327,876)   (261,044)
Sale of assets to associated companies...................................               --           --     154,596
Other (Note 7)...........................................................          (25,857)      34,132       2,888
                                                                                ----------   ----------   ---------
       Net cash used for investing activities............................         (148,475)    (442,711)   (248,987)
                                                                                ----------   ----------   ---------
Net increase (decrease) in cash and cash equivalents.....................          (18,629)      15,924     (13,681)
Cash and cash equivalents at beginning of year...........................           20,512        4,588      18,269
                                                                                ----------   ----------   ---------
Cash and cash equivalents at end of year.................................       $    1,883   $   20,512   $   4,588
                                                                                ==========   ==========   =========

SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
     Interest (net of amounts capitalized)...............................       $  103,632   $  118,535   $ 180,263
                                                                                ==========   ==========   =========
     Income taxes........................................................       $  250,564   $  126,558   $ 240,882
                                                                                ==========   ==========   =========


<FN>


The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

</FN>
</TABLE>

                                                        19
<PAGE>


<TABLE>
<CAPTION>

                                                        OHIO EDISON COMPANY

                                                 CONSOLIDATED STATEMENTS OF TAXES

For the Years Ended December 31,                                                 2003         2002         2001
------------------------------------------------------------------------------------------------------------------
                                                                                         (In thousands)
<S>                                                                             <C>         <C>           <C>
GENERAL TAXES:
Real and personal property.............................................         $ 51,074    $   65,709    $   45,132
State gross receipts*..................................................           18,028        18,516        45,271
Ohio kilowatt-hour excise*.............................................           91,296        85,762        55,795
Social security and unemployment.......................................            6,992         5,438         4,159
Other..................................................................            2,688         1,596         3,149
                                                                                --------    ----------    ----------
     Total general taxes...............................................         $170,078    $  177,021    $  153,506
                                                                                ========    ==========    ==========


PROVISION FOR INCOME TAXES:
Currently payable-
   Federal.............................................................         $270,345    $  280,587    $  265,305
   State...............................................................           81,505        55,796        51,121
                                                                                --------    ----------    ----------
                                                                                 351,850       336,383       316,426
                                                                                --------    ----------    ----------

Deferred, net-
   Federal.............................................................          (57,503)      (44,552)      (56,105)
   State...............................................................          (16,038)      (22,184)       (7,840)
                                                                                --------    ----------    ----------
                                                                                 (73,541)      (66,736)      (63,945)
                                                                                --------    ----------    ----------
Investment tax credit amortization.....................................          (14,747)      (13,732)      (13,346)
                                                                                --------    ----------    ----------
     Total provision for income taxes..................................         $263,562    $  255,915    $  239,135
                                                                                ========    ==========    ==========


INCOME STATEMENT CLASSIFICATION
OF PROVISION FOR INCOME TAXES:
Operating income.......................................................         $216,979    $  229,001    $  220,678
Other income...........................................................           24,194        26,914        18,457
Cumulative effect of accounting change.................................           22,389            --            --
                                                                                --------    ----------    ----------
     Total provision for income taxes..................................         $263,562    $  255,915    $  239,135
                                                                                ========    ==========    ==========


RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes..........................         $588,207    $  612,074    $  589,347
                                                                                ========    ==========    ==========
Federal income tax expense at statutory rate...........................         $205,872    $  214,225    $  206,271
Increases (reductions) in taxes resulting from-
   Amortization of investment tax credits..............................          (14,747)      (13,732)      (13,346)
   State income taxes, net of federal income tax benefit...............           42,554        21,848        28,133
   Amortization of tax regulatory assets...............................           33,219        30,659        32,020
   Other, net..........................................................           (3,336)        2,915       (13,943)
                                                                                --------    ----------    ----------
     Total provision for income taxes..................................         $263,562    $  255,915    $  239,135
                                                                                ========    ==========    ==========


ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences.............................................         $406,783    $  397,930    $  374,138
Allowance for equity funds used during construction....................           30,493        34,407        36,587
Regulatory transition charge...........................................          345,723       527,502       675,652
Customer receivables for future income taxes...........................           44,382        49,486        54,600
Deferred sale and leaseback costs......................................          (67,837)      (71,830)      (77,099)
Unamortized investment tax credits.....................................          (29,031)      (33,421)      (38,680)
Deferred gain for asset sale to affiliated company.....................           53,010        70,812        85,311
Other comprehensive income.............................................          (27,219)      (41,570)           --
Other (Note 7).........................................................          111,387        84,313        64,886
                                                                                --------    ----------    ----------
     Net deferred income tax liability.................................         $867,691    $1,017,629    $1,175,395
                                                                                ========    ==========    ==========
<FN>


* Collected from customers through regulated rates and included in revenue on the Consolidated Statements of Income.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

</FN>
</TABLE>

                                                         20


<PAGE>


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

           The consolidated financial statements include Ohio Edison Company
(Company) and its wholly owned subsidiaries. Pennsylvania Power Company (Penn)
is the Company's principal operating subsidiary. The Company is a wholly owned
subsidiary of FirstEnergy Corp. FirstEnergy also holds directly all of the
issued and outstanding common shares of its other principal electric utility
operating subsidiaries, including The Cleveland Electric Illuminating Company
(CEI), The Toledo Edison Company (TE), American Transmission Systems, Inc.
(ATSI), Jersey Central Power & Light Company (JCP&L), Metropolitan Edison
Company (Met-Ed) and Pennsylvania Electric Company (Penelec).

           The Company and Penn (Companies) follow the accounting policies and
practices prescribed by the Securities and Exchange Commission (SEC), the Public
Utilities Commission of Ohio (PUCO), the Pennsylvania Public Utility Commission
(PPUC) and the Federal Energy Regulatory Commission (FERC). The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States (GAAP) requires management to make periodic estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues
and expenses and the disclosure of contingent assets and liabilities. Actual
results could differ from these estimates. The Company's consolidated financial
statements for the year ended December 31, 2002 were restated to reflect a
change in the method of amortizing costs being recovered under the Ohio
transition plan. Certain prior year amounts have been reclassified to conform
with the current year presentation, as described further in Note 1(F).

     (A) CONSOLIDATION-

           The Company consolidates all majority-owned subsidiaries, over which
the Company exercises control and, when applicable, entities for which the
Company has a controlling financial interest. Intercompany transactions and
balances are eliminated in consolidation. Investments in nonconsolidated
affiliates (20-50 percent owned companies, joint ventures and partnerships) over
which the Company has the ability to exercise significant influence, but not
control, are accounted for on the equity basis.

     (B) REVENUES-

           The Companies' principal business is providing electric service to
customers in central and northeastern Ohio and western Pennsylvania. The
Companies' retail customers are metered on a cycle basis. Revenue is recognized
for unbilled electric service provided through the end of the year.

           Receivables from customers include sales to residential, commercial
and industrial customers located in the Companies' service area and sales to
wholesale customers. There was no material concentration of receivables as of
December 31, 2003 or 2002, with respect to any particular segment of the
Companies' customers. Total customer receivables were $281 million (billed -
$165 million and unbilled - $116 million) and $297 million (billed - $169
million and unbilled - $128 million) as of December 31, 2003 and 2002,
respectively.

     (C) REGULATORY MATTERS-

         Ohio-

           In July 1999, Ohio's electric utility restructuring legislation,
which allowed Ohio electric customers to select their generation suppliers
beginning January 1, 2001, was signed into law. Among other things, the
legislation provided for a 5% reduction on the generation portion of residential
customers' bills and the opportunity to recover transition costs, including
regulatory assets, from January 1, 2001 through December 31, 2005 (market
development period). The period for the recovery of regulatory assets only can
be extended up to December 31, 2010. The PUCO was authorized to determine the
level of transition cost recovery, as well as the recovery period for the
regulatory assets portion of those costs, in considering each Ohio electric
utility's transition plan application.

            In July 2000, the PUCO approved FirstEnergy's transition plan for
the Company, CEI and TE (Ohio Companies) as modified by a settlement agreement
with major parties to the transition plan. The application of Statement of
Financial Accounting Standards No. (SFAS) 71 , "Accounting for the
Effects of Certain Types of Regulation" to the Company's generation business was
discontinued with the issuance of the PUCO transition plan order, as described
further below. Major provisions of the settlement agreement consisted of
approval of recovery of the Company's generation-related transition costs as
filed of $1.6 billion net of deferred income taxes and transition costs related
to regulatory assets as filed of $1.0 billion net of deferred income taxes, with
recovery through no later than 2006 for the Company except where a longer period
of recovery is provided for in the settlement agreement. The generation-related
transition costs include $1.0 billion, net of deferred income taxes, of impaired
generating assets recognized as regulatory assets as described further below and
$1.2 billion, net of deferred income taxes, of above market operating lease
costs.

                                        21

<PAGE>

           Also as part of the settlement agreement, FirstEnergy is giving
preferred access over its subsidiaries to nonaffiliated marketers, brokers and
aggregators to 560 megawatts (MW) of generation capacity through 2005 at
established prices for sales to the Company's retail customers. Customer prices
are frozen through the five-year market development period, which runs through
the end of 2005, except for certain limited statutory exceptions, including the
5% reduction referred to above. In February 2003, the Company was authorized
increases in annual revenues aggregating approximately $41 million to recover
its higher tax costs resulting from the Ohio deregulation legislation.

           The Company's customers choosing alternative suppliers receive an
additional incentive applied to the shopping credit (generation component) of
45% for residential customers, 30% for commercial customers and 15% for
industrial customers. The amount of the incentive is deferred for future
recovery from customers. Subject to approval by the PUCO, recovery will be
accomplished by extending the transition cost recovery period.

           On October 21, 2003, the Ohio Companies filed an application with the
PUCO to establish generation service rates beginning January 1, 2006, in
response to expressed concerns by the PUCO about price and supply uncertainty
following the end of the market development period. The filing included two
options:

           o   A competitive auction, which would establish a price for
               generation that customers would be charged during the period
               covered by the auction, or

           o   A Rate Stabilization Plan, which would extend current generation
               prices through 2008, ensuring adequate supply and continuing
               FirstEnergy's support of energy efficiency and economic
               development efforts.

           Under the first option, an auction would be conducted to secure
generation service for the Ohio Companies' customers. Beginning in 2006,
customers would pay market prices for generation as determined by the auction.

           Under the Rate Stabilization Plan option, customers would have price
and supply stability through 2008 - three years beyond the end of the market
development period - as well as the benefits of a competitive market. Customer
benefits would include: customer savings by extending the current five percent
discount on generation costs and other customer credits; maintaining current
distribution base rates through 2007; market-based auctions that may be
conducted annually to ensure that customers pay the lowest available prices;
extension of FirstEnergy's support of energy-efficiency programs and the
potential for continuing the program to give preferred access to nonaffiliated
entities to generation capacity if shopping drops below 20%. Under the proposed
plan, OE is requesting:

           o   Extension of the transition cost amortization period from 2006 to
               2007;

           o   Deferral of interest costs on the accumulated shopping incentive
               and other cost deferrals as new regulatory assets; and

           o  Ability to initiate a request to increase generation rates only
               under certain limited conditions.

           On January 7, 2004, the PUCO staff filed testimony on the proposed
rate plan generally supporting the Rate Stabilization Plan as opposed to the
competitive auction proposal. Hearings began on February 11, 2004. On February
23, 2004, after consideration of PUCO Staff comments and testimony as well as
those provided by some of the intervening parties, FirstEnergy made certain
modifications to the Rate Stabilization Plan. A decision is expected from the
PUCO in the Spring of 2004.

           On November 25, 2003, the PUCO ordered FirstEnergy to file a plan
with the PUCO no later than March 1, 2004, illustrating how FirstEnergy will
address certain problems identified by the U.S.-Canada Power System Outage Task
Force (in connection with the August 14, 2003 regional power outage) and
addressing how FirstEnergy proposes to upgrade its control room computer
hardware and software, improve its control room training procedures and improve
the training of control room operators to ensure that similar problems do not
occur in the future. The PUCO, in consultation with the North American Electric
Reliability Council, will review the plan before determining the next steps in
the proceeding.

         Pennsylvania-

           Pennsylvania enacted its electric utility competition law in 1996
with the phase-in of customer choice for generation suppliers completed as of
January 1, 2001. In 1998, the PPUC authorized a rate restructuring plan for
Penn, which essentially resulted in the deregulation of Penn's generation
business.

           In late 2003, the PPUC issued a Tentative Order implementing new
reliability benchmarks and standards. In connection therewith, the PPUC
commenced a rulemaking procedure to amend the Electric Service Reliability
Regulations to implement these new benchmarks, and create additional reporting
on reliability. Although neither the


                                        22
<PAGE>







Tentative Order nor the Reliability Rulemaking has been finalized, the PPUC
ordered all Pennsylvania utilities to begin filing quarterly reports on November
1, 2003. The comment period for both the Tentative Order and the Proposed
Rulemaking Order has closed. Penn is currently awaiting the PPUC to issue a
final order in both matters. The order will determine (1) the standards and
benchmarks to be utilized, and (2) the details required in the quarterly and
annual reports. It is expected that these Orders will be finalized in March
2004.

           On January 16, 2004, the PPUC initiated a formal investigation of
Penn's levels of compliance with the Public Utility Code and the PPUC's
regulations and orders with regard to reliable electric service. The
investigation is to determine whether Penn's reliability performance has
deteriorated to a point below the level of service reliability that existed
prior to the implementation of electric restructuring in Pennsylvania. Hearings
will be held in August in this investigation and the Administrative Law Judge
has been directed to issue a Recommended Decision by September 30, 2004, in
order to allow the PPUC time to issue a Final Order before December 16, 2004.
Penn is unable to predict the outcome of the investigation or the impact of the
PPUC Order.

         Transition Cost Amortization -

           The Company amortizes transition costs (see Regulatory Matters -
Ohio) using the effective interest method. Under the current Ohio transition
plan, total transition cost amortization is expected to approximate the
following for 2004 through 2006.

                               (In millions)
          ---------------------------------
          2004..................   $471
          2005..................    553
          2006..................    146
          ---------------------------------


           The decrease in amortization in 2006 results from the termination of
generation-related transition cost recovery under the Ohio transition plan.

         Regulatory Assets-

           The Companies recognize, as regulatory assets, costs which the FERC,
PUCO and PPUC have authorized for recovery from customers in future periods.
Without such authorization, the costs would have been charged to income as
incurred. All regulatory assets are expected to continue to be recovered from
customers under the Companies' respective transition and rate restructuring
plans. Based on those plans, the Companies continue to bill and collect
cost-based rates for their transmission and distribution services, which remain
regulated; accordingly, it is appropriate that the Companies continue the
application of SFAS 71 to those operations.

           Net regulatory assets on the Consolidated Balance Sheets are
comprised of the following:

                                                        2003             2002
------------------------------------------------------------------------------
                                                             (In millions)
Regulatory transition charge......................    $1,331            $1,761
Customer shopping incentives......................       140                79
Customer receivables for future income taxes......       115               127
Loss on reacquired debt...........................        29                28
Employee postretirement benefit costs.............         6                 9
Nuclear decommissioning costs.....................       (72)               --
Component removal costs (Note 1(F))...............       (72)              (67)
Other.............................................         1                 1
------------------------------------------------------------------------------
  Total...........................................    $1,478            $1,938
==============================================================================


         Regulatory Accounting for Generation Operations-

           The application of SFAS 71 was discontinued with respect to the
Companies' generation operations. The SEC issued interpretive guidance regarding
asset impairment measurement providing that any supplemental regulated cash
flows such as a competitive transition charge (CTC) should be excluded from the
cash flows of assets in a portion of the business not subject to regulatory
accounting practices. If those assets are impaired, a regulatory asset should be
established if the costs are recoverable through regulatory cash flows.
Consistent with the SEC guidance, $1.2 billion of impaired plant investments
were recognized by the Company as regulatory assets recoverable as transition
costs through future regulatory cash flows and $227 million were recognized for
Penn related to its 1998 impairment of its nuclear generating unit investments
to be recovered through a CTC over a seven-year transition period.

                                      23

<PAGE>

           Net assets included in utility plant relating to the operations for
which the application of SFAS 71 was discontinued, compared to the respective
company's total assets as of December 31, 2003 were $976 million and $6.59
billion, respectively, for the Company and $92 million and $921 million,
respectively, for Penn.

     (D) UTILITY PLANT AND DEPRECIATION-

           Utility plant reflects the original cost of construction (except for
the Companies' nuclear generating units which were adjusted to fair value)
including payroll and related costs such as taxes, employee benefits,
administrative and general costs, and interest costs incurred to place the
assets in service. The Companies' accounting policy for planned major
maintenance projects is to recognize liabilities as they are incurred.

           The Companies provide for depreciation on a straight-line basis at
various rates over the estimated lives of property included in plant in service.
The annual composite rate for the Company's electric plant was approximately
2.8% in 2003 and 2.7% in 2002 and 2001. The annual composite rate for Penn's
electric plant was approximately 2.6% in 2003 and 2.9% in 2002 and 2001.

       Nuclear Fuel -

           Nuclear fuel is recorded at original cost, which includes material,
enrichment, fabrication and interest costs incurred prior to reactor load. The
Companies amortize the cost of nuclear fuel based on the rate of consumption.

     (E) COMMON OWNERSHIP OF GENERATING FACILITIES-

           The Companies, together with CEI and TE, own and/or lease, as tenants
in common, various power generating facilities. Each of the companies is
obligated to pay a share of the costs associated with any jointly owned facility
in the same proportion as its interest. The Companies' portions of operating
expenses associated with jointly owned facilities are included in the
corresponding operating expenses on the Consolidated Statements of Income. The
amounts reflected on the Consolidated Balance Sheet under utility plant as of
December 31, 2003 include the following:

<TABLE>
<CAPTION>

                                                                                                  Companies'
                                     Utility          Accumulated           Construction          Ownership/
                                      Plant           Provision for             Work in           Leasehold
Generating Units                    in Service        Depreciation             Progress            Interest
-------------------------------------------------------------------------------------------------------------
                                                                  (In millions)
<S>                                  <C>                  <C>                     <C>               <C>
W. H. Sammis #7..................    $  335               $  165                  $ --              68.80%
Bruce Mansfield #1, #2 and #3....       991                  529                    --              67.18%
Beaver Valley #1 and #2..........       192                   35                   110              77.81%
Perry............................       357                  352                     8              35.24%
-------------------------------------------------------------------------------------------------------------
     Total.......................    $1,875               $1,081                  $118
=============================================================================================================

</TABLE>


     (F) ASSET RETIREMENT OBLIGATION-

           In January 2003, the Companies implemented SFAS 143, "Accounting for
Asset Retirement Obligations", which provides accounting standards for
retirement obligations associated with tangible long-lived assets. This
statement requires recognition of the fair value of a liability for an asset
retirement obligation (ARO) in the period in which it is incurred. The
associated asset retirement costs are capitalized as part of the carrying amount
of the long-lived asset. Over time the capitalized costs are depreciated and the
present value of the asset retirement liability increases, resulting in a period
expense. However, rate-regulated entities may recognize a regulatory asset or
liability instead if the criteria for such treatment are met. Upon retirement, a
gain or loss would be recognized if the cost to settle the retirement obligation
differs from the carrying amount.

           The Companies identified applicable legal obligations as defined
under the new standard for nuclear power plant decommissioning and reclamation
of a sludge disposal pond related to the Bruce Mansfield Plant. The ARO
liability as of the date of adoption of SFAS 143 was $297.6 million, including
accumulated accretion for the period from the date the liability was incurred to
the date of adoption. Accretion during 2003 was $20.1 million, bringing the ARO
liability as of December 31, 2003 to $317.7 million. The ARO includes the
Companies' obligation for nuclear decommissioning of the Beaver Valley and Perry
generating facilities. The Companies' share of the obligation to decommission
these units was developed based on site specific studies performed by an
independent engineer. The Companies utilized an expected cash flow approach (as
discussed in FASB Concepts Statement No. 7, "Using Cash Flow Information and
Present Value in Accounting Measurements") to measure the fair value of the
nuclear decommissioning ARO. The Companies maintain nuclear decommissioning
trust funds that are legally restricted for purposes of settling the nuclear
decommissioning ARO. As of December 31, 2003, the fair value of the
decommissioning trust assets was $376.4 million.

           In accordance with SFAS 143, the Companies ceased the accounting
practice of depreciating non-regulated generation assets using a cost of removal
component in the depreciation rates. That practice recognized accumulated


                                        24

<PAGE>

depreciation in excess of the historical cost of an asset because the removal
cost would exceed the estimated salvage value. Beginning in 2003, the cost of
removal related to non-regulated generation assets is charged to expense rather
than to the accumulated provision for depreciation. In accordance with SFAS 71,
the cost of removal on regulated plant assets continues to be accounted for as a
component of depreciation rates and is recognized as a regulatory liability.

           The following table provides the effect on income as if SFAS 143 had
been applied during 2002 and 2001.


Effect of the Change in Accounting
Principle Applied Retroactively                           2002            2001
------------------------------------------------------------------------------
                                                              (In millions)
Reported net income....................................   $356            $350
Increase (Decrease):
Elimination of decommissioning expense.................     30              30
Depreciation of asset retirement cost..................     (1)             (1)
Accretion of ARO liability.............................    (11)            (10)
Non-regulated generation cost of removal component, net      5               4
Income tax effect......................................     (9)             (9)
-------------------------------------------------------------------------------
Net earnings increase..................................     14              14
------------------------------------------------------------------------------
Net income adjusted....................................   $370            $364
==============================================================================


           The following table provides the year-end balance of the ARO for
2002, as if SFAS 143 had been adopted on January 1, 2002.

    Adjusted ARO Reconciliation                      2002
    --------------------------------------------------------
                                                (In millions)
    Beginning balance as of January 1, 2002         $278.8
    Accretion in 2002                                 18.8
    --------------------------------------------------------
    Ending balance as of December 31, 2002          $297.6
    --------------------------------------------------------


     (G) STOCK-BASED COMPENSATION-

           FirstEnergy applies the recognition and measurement principles of
Accounting Principles Board Opinion No. 25 (APB 25), "Accounting for Stock
Issued to Employees" and related Interpretations in accounting for its
stock-based compensation plans (see Note 3(C)). No material stock-based employee
compensation expense is reflected in net income as all options granted under
those plans had an exercise price equal to the market value of the underlying
common stock on the grant date resulting in substantially no intrinsic value.

           If FirstEnergy had accounted for employee stock options under the
fair value method of SFAS 123, "Accounting for Stock Compensation," a higher
value would have been assigned to the options granted. The weighted average
assumptions used in valuing the options and their resulting estimated fair
values would be as follows:

                                     2003       2002       2001
-----------------------------------------------------------------
Valuation assumptions:
  Expected option term (years).       7.9        8.1        8.3
  Expected volatility..........     26.91%     23.31%     23.45%
  Expected dividend yield......      5.09%      4.36%      5.00%
  Risk-free interest rate......      3.67%      4.60%      4.67%
Fair value per option..........     $5.09      $6.45      $4.97
-----------------------------------------------------------------


           The effects of applying fair value accounting to the Companies' stock
options would not materially affect net income.

     (H) INCOME TAXES-

           Details of the total provision for income taxes are shown on the
Consolidated Statements of Taxes. The Company records income taxes in accordance
with the liability method of accounting. Deferred income taxes reflect the net
tax effect of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for tax
purposes. Investment tax credits, which were deferred when utilized, are being
amortized over the recovery period of the related property. Deferred income tax
liabilities related to tax and accounting basis differences and tax credit
carryforward items are recognized at the statutory income tax rates in effect
when the liabilities are expected to be paid. The Companies are included in
FirstEnergy's consolidated federal income tax return. The consolidated tax
liability is allocated on a "stand-alone" company basis, with the Companies
recognizing any tax losses or credits they contribute to the consolidated
+return.
                                      25
<PAGE>


     (I) CUMULATIVE EFFECT OF ACCOUNTING CHANGE-

           Results for 2003 include an after-tax credit to net income of $31.7
million recorded upon the adoption of SFAS 143 in January 2003. The Companies
identified applicable legal obligations as defined under the new standard for
nuclear power plant decommissioning and reclamation of a sludge disposal pond at
the Bruce Mansfield Plant. As a result of adopting SFAS 143 in January 2003,
asset retirement costs of $133.7 million were recorded as part of the carrying
amount of the related long-lived asset, offset by accumulated depreciation of
$25.2 million. The ARO liability at the date of adoption was $297.6 million,
including accumulated accretion for the period from the date the liability was
incurred to the date of adoption. As of December 31, 2002, the Companies had
recorded decommissioning liabilities of $281 million. Penn expects substantially
all of its nuclear decommissioning costs to be recoverable in rates over time.
Therefore, Penn recognized a regulatory liability of $69 million upon adoption
of SFAS 143 for the transition amounts related to establishing the ARO for
nuclear decommissioning. The remaining cumulative effect adjustment for
unrecognized depreciation and accretion, offset by the reduction in the existing
decommissioning liabilities and the reversal of accumulated estimated removal
costs for non-regulated generation assets, resulted in a $54.1 million increase
to income, or $31.7 million net of income taxes.

     (J) PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

           FirstEnergy provides noncontributory defined benefit pension plans
that cover substantially all of the Companies' employees. The trusteed plans
provide defined benefits based on years of service and compensation levels.
FirstEnergy's funding policy is based on actuarial computations using the
projected unit credit method. No pension contributions were required during the
three years ended December 31, 2003.

           FirstEnergy provides a minimum amount of noncontributory life
insurance to retired employees in addition to optional contributory insurance.
Health care benefits, which include certain employee contributions, deductibles
and copayments, are also available to retired employees, their dependents and,
under certain circumstances, their survivors. The Companies recognize the
expected cost of providing other postretirement benefits to employees and their
beneficiaries and covered dependents from the time employees are hired until
they become eligible to receive those benefits.

           Pension and OPEB costs are affected by employee demographics
(including age, compensation levels, and employment periods), the level of
contributions made to the plans, and earnings on plan assets. Such factors may
be further affected by business combinations (such as FirstEnergy's merger with
GPU, Inc. in November 2001), which impacts employee demographics, plan
experience and other factors. Pension and OPEB costs may also be affected by
changes to key assumptions, including anticipated rates of return on plan
assets, the discount rates and health care trend rates used in determining the
projected benefit obligations and pension and OPEB costs. FirstEnergy uses a
December 31 measurement date for the majority of its plans.

           Plan amendments to retirement health care benefits in 2003 and 2002,
relate to changes in benefits provided and cost-sharing provisions, which
reduced FirstEnergy's obligation by $123 and $121 million, respectively. In
early 2004, FirstEnergy announced that it would amend the benefit provisions of
its health care benefits plan and both employees and retirees would share in
more of the benefit costs.

           On December 8, 2003, President Bush signed into law a bill that
expands Medicare, primarily adding a prescription drug benefit for
Medicare-eligible retirees starting in 2006. FirstEnergy anticipates that the
benefits it pays after 2006 will be lower as a result of the new Medicare
provisions. Due to uncertainties surrounding some of the new Medicare provisions
and a lack of authoritative accounting guidance about these issues, FirstEnergy
deferred the recognition of the impact of the new Medicare provisions as
provided by FASB Staff Position 106-1. The final accounting guidance could
require changes to previously reported information.

           The following sets forth the funded status of the plans and amounts
recognized in the FirstEnergy's Consolidated Balance Sheets as of December 31:

                                       26

<PAGE>


<TABLE>
<CAPTION>


         Obligations and Funded Status                 Pension Benefits            Other Benefits
                                                      -----------------           ----------------
         As of December 31                             2003         2002           2003       2002
         ------------------------------------------------------------------------------------------
                                                                       (In millions)
         <S>                                          <C>          <C>           <C>         <C>
         Change in benefit obligation
         Benefit obligation at beginning of year..    $3,866       $3,548        $ 2,077     $1,582
         Service cost.............................        66           59             43         28
         Interest cost............................       253          249            136        114
         Plan participants' contributions.........        --           --              6         --
         Plan amendments..........................        --           --           (123)      (121)
         Actuarial loss...........................       222          268            323        440
         GPU acquisition..........................        --          (12)            --        110
         Benefits paid............................      (245)        (246)           (94)       (76)
                                                      ------       ------        -------     ------
         Benefit obligation at end of year........    $4,162       $3,866        $ 2,368     $2,077
                                                      ======       ======        =======     ======

         Change in fair value of plan assets
         Fair value of plan assets at beginning
          of year.................................    $2,889       $3,484        $   473     $  535
         Actual return on plan assets.............       671         (349)            88        (57)
         Company contribution.....................        --           --             68         31
         Plan participants' contribution..........        --           --              2         --
         Benefits paid............................      (245)        (246)           (94)       (36)
                                                      ------       ------        -------     ------
         Fair value of plan assets at end of year.    $3,315       $2,889        $   537     $  473
                                                      ======       ======        =======     ======

         Funded status............................    $ (847)      $ (977)       $(1,831)    (1,604)
         Unrecognized net actuarial loss..........       919        1,186            994        752
         Unrecognized prior service cost
          (benefit)...............................        72           78           (221)      (107)
         Unrecognized net transition obligation...        --           --             83         92
                                                      ------       ------        -------     ------
         Net asset (liability) recognized.........    $  144       $  287        $  (975)    $ (867)
                                                      ======       ======        =======     ======

         Amounts Recognized in the
         Consolidated Balance Sheets
         As of December 31
         -----------------------------------------

         Accrued benefit cost.....................    $ (438)      $ (548)         $(975)     $(867)
         Intangible assets........................        72           78             --         --
         Accumulated other comprehensive loss.....       510          757             --         --
                                                      ------       ------          -----     ------
         Net amount recognized....................    $  144       $  287          $(975)     $(867)
                                                      ======       ======          =====      =====
         Companies' share of net amount
           recognized.............................    $   53       $   57          $(249)     $(171)
                                                      ======       ======          =====      =====

         Increase (decrease) in minimum liability
           included in other comprehensive income
           (net of tax)...........................    $ (145)      $  444          $  --   $     --

         Weighted-Average Assumptions Used
         to Determine Benefit Obligations
         As of December 31
         -----------------------------------------

         Discount rate...........................       6.25%        6.75%          6.25%      6.75%
         Rate of compensation increase...........       3.50%        3.50%

         Allocation of Plan Assets
         As of December 31
         -----------------------------------------
         Asset Category
         Equity securities.....................           70%          61%            71%        58%
         Debt securities.......................           27           35             22         29
         Real estate...........................            2            2             --         --
         Other.................................            1            2              7         13
                                                         ---          ---            ---         --
         Total.................................          100%         100%           100%       100%
                                                         ===          ===            ===        ===

         Information for Pension Plans With an
         Accumulated Benefit Obligation in
         Excess of Plan Assets                         2003         2002
         -----------------------------------------     ----         ----
                                                         (In millions)
         Projected benefit obligation.............    $4,162       $3,866
         Accumulated benefit obligation...........     3,753        3,438
         Fair value of plan assets................     3,315        2,889

</TABLE>


         FirstEnergy's net pension and other postretirement benefit costs for
         the three years ended December 31, 2003 were computed as follows:


                                                    27
<PAGE>

<TABLE>
<CAPTION>


                                                        Pension Benefits          Other Benefits
                                                        ----------------          --------------
         Components of Net Periodic Benefit Costs      2003   2002   2001       2003    2002    2001
         ---------------------------------------------------------------------------------------------
                                                                     (In millions)
         <S>                                           <C>    <C>    <C>        <C>     <C>     <C>
         Service cost............................      $  66  $  59  $  35      $ 43    $ 29    $ 18
         Interest cost...........................        253    249    133       137     114      65
         Expected return on plan assets..........       (248)  (346)  (205)      (43)    (52)    (10)
         Amortization of prior service cost......          9      9      9        (9)      3       3
         Amortization of transition obligation
          (asset)................................         --     --     (2)        9       9       9
         Recognized net actuarial loss...........         62     --     --        40      11       5
         Voluntary early retirement program......         --     --      6        --      --       2
                                                       -----  -----  -----      ----    ----    ----
         Net periodic cost (income)..............      $ 142  $ (29) $ (24)     $177    $114    $ 92
                                                       =====  =====  =====      ====    ====    ====
         Companies' share of net benefit costs...      $  24  $   3  $  (3)     $ 43    $ 15    $ 16
                                                       =====  =====  =====      ====    ====    ====

         Weighted-Average Assumptions Used
         to Determine Net Periodic Benefit Cost
         for Years Ended December 31

         Discount rate..........................        6.75%  7.25%  7.75%     6.75%   7.25%   7.75%
         Expected long-term return on plan
           assets...............................        9.00% 10.25% 10.25%     9.00%  10.25%  10.25%

         Rate of compensation increase..........        3.50%  4.00%  4.00%

</TABLE>


           In selecting an assumed discount rate, FirstEnergy considers
currently available rates of return on high-quality fixed income investments
expected to be available during the period to maturity of the pension and other
postretirement benefit obligations. The assumed rate of return on pension plan
assets considers historical market returns and economic forecasts for the types
of investments held by the Company's pension trusts. The long-term rate of
return is developed considering the portfolio's asset allocation strategy.

Assumed health care cost trend rates
As of December 31                                        2003          2002
------------------------------------------------------------------------------
Health care cost trend rate assumed for next
  year (pre/post-Medicare)..........................   10%-12%       10%-12%
Rate to which the cost trend rate is assumed to
  decline (the ultimate trend rate).................        5%            5%
Year that the rate reaches the ultimate trend
  rate (pre/post-Medicare)..........................  2009-2011     2008-2010


           Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects:

                                               1-Percentage-     1-Percentage-
                                               Point Increase    Point Decrease
 ------------------------------------------------------------------------------
                                                       (In millions)

 Effect on total of service and interest cost..   $ 26              $ (19)
 Effect on postretirement benefit obligation...   $233              $(212)


           FirstEnergy employs a total return investment approach whereby a mix
of equities and fixed income investments are used to maximize the long-term
return of plan assets for a prudent level of risk. Risk tolerance is established
through careful consideration of plan liabilities, plan funded status, and
corporate financial condition. The investment portfolio contains a diversified
blend of equity and fixed-income investments. Furthermore, equity investments
are diversified across U.S. and non-U.S. stocks, as well as growth, value, and
small and large capitalizations. Other assets such as real estate are used to
enhance long-term returns while improving portfolio diversification. Derivatives
may be used to gain market exposure in an efficient and timely manner; however,
derivatives are not used to leverage the portfolio beyond the market value of
the underlying investments. Investment risk is measured and monitored on a
continuing basis through periodic investment portfolio reviews, annual liability
measurements, and periodic asset/liability studies.

           As a result of GPU Service Inc. merging with FirstEnergy Service
Company in the second quarter of 2003, operating company employees of GPU
Service were transferred to the former GPU operating companies. Accordingly,
FirstEnergy requested an actuarial study to update the pension liabilities for
each of its subsidiaries. Based on the actuary's report, the accrued pension
costs for the Companies as of June 30, 2003 increased by $67 million. The
corresponding adjustment related to this change decreased other comprehensive
income and deferred income taxes and increased the payable to associated
companies.

           Due to the increased market value of their pension plan
assets, the Companies reduced their minimum liability as prescribed by SFAS 87
as of December 31, 2003 by $85 million, recording an increase of $5 million in
an intangible asset and crediting OCI by $53 million (offsetting previously
recorded deferred tax benefits by $37 million). The remaining balance in OCI of
$62 million will reverse in future periods to the extent the fair value of trust
assets exceeds the accumulated benefit obligation. The accrued pension cost was
reduced to $81 million as of December 31, 2003.

           FirstEnergy does not expect to contribute to its pension plans in
2004 and expects to contribute $16 million to its other postretirement benefit
plans in 2004.

                                           28
<PAGE>


     (K) TRANSACTIONS WITH AFFILIATED COMPANIES-

           Operating revenues, operating expenses and other income include
transactions with affiliated companies, primarily ATSI, FirstEnergy Solutions
Corp. (FES) and FirstEnergy Service Company (FESC). The Ohio transition plan, as
discussed in the "Regulatory Matters" section, resulted in the corporate
separation of FirstEnergy's regulated and unregulated operations in 2001. FES
operates the generation businesses of the Companies, CEI and TE. As a result,
the Companies entered into power supply agreements (PSA) whereby FES purchases
all of the Companies' nuclear generation and the Companies purchase their power
from FES to meet their "provider of last resort" obligations. The primary
affiliated companies transactions are as follows:


                                        2003           2002           2001
-----------------------------------------------------------------------------
                                                    (In millions)
Operating Revenues:
PSA revenues from FES................   $384           $329          $  356
Generating units rent from FES.......    178            178             179
Ground lease with ATSI...............     12             12              12

Operating Expenses:
Purchased power under PSA............    902            912           1,026
Transmission expense.................     65             85              61
FESC support services................    116            141             147

Other Income:
Interest income from ATSI............     16             16              16
Interest income from FES.............     12             12              12
------------------------------------------------------------------------------



           FirstEnergy does not bill directly or allocate any of its costs to
any subsidiary company. Costs are allocated to the Companies from FESC, a
subsidiary of FirstEnergy and a "mutual service company" as defined in Rule 93
of the Public Utility Holding Company Act of 1935 (PUHCA). The majority of costs
are directly billed or assigned at no more than cost as determined by PUHCA Rule
91. The remaining costs are for services that are provided on behalf of more
than one company, or costs that cannot be precisely identified and are allocated
using formulas that are filed annually with the SEC on Form U-13-60. The current
allocation or assignment formulas used and their bases include multiple factor
formulas: each company's proportionate amount of FirstEnergy's aggregate direct
payroll, number of employees, asset balances, revenues, number of customers,
other factors and specific departmental charge ratios. Management believes that
these allocation methods are reasonable.

     (L) CASH AND FINANCIAL INSTRUMENTS-

           All temporary cash investments purchased with an initial maturity of
three months or less are reported as cash equivalents on the Consolidated
Balance Sheets at cost, which approximates their fair market value.

           All borrowings with initial maturities of less than one year are
defined as financial instruments under GAAP and are reported on the Consolidated
Balance Sheets at cost, which approximates their fair market value. The
following sets forth the approximate fair value and related carrying amounts of
all other long-term debt, preferred stock subject to mandatory redemption and
investments other than cash and cash equivalents as of December 31:


<TABLE>
<CAPTION>

                                                          2003                           2002
----------------------------------------------------------------------------------------------------
                                                  Carrying      Fair             Carrying      Fair
                                                    Value      Value               Value      Value
----------------------------------------------------------------------------------------------------
                                                                     (In millions)
<S>                                                <C>         <C>                <C>         <C>
Long-term debt.................................    $1,639      $1,677             $1,776      $1,861
Preferred stock*...............................    $   14      $   14             $   14      $   14
Investments other than cash and cash equivalents:
   Debt securities:
   - Maturity (5-10 years).....................    $  550      $  534             $  570      $  539
   - Maturity (more than 10 years).............       469         548                458         532
   Equity securities...........................        --          --                 12          12
   All other...................................       430         430                361         361
----------------------------------------------------------------------------------------------------
                                                   $1,449      $1,512             $1,401      $1,444
====================================================================================================

<FN>

      * The December 31, 2003 amount is classified as debt under SFAS 150.

</FN>
</TABLE>


           The fair values of long-term debt and preferred stock reflect the
present value of the cash outflows relating to those securities based on the
current call price, the yield to maturity or the yield to call, as deemed
appropriate at the end

                                                29
<PAGE>



of each respective year. The yields assumed were based on securities with
similar characteristics offered by a corporation with credit ratings similar to
the Companies' ratings.

           The fair value of investments other than cash and cash equivalents
represent cost (which approximates fair value) or the present value of the cash
inflows based on the yield to maturity. The yields assumed were based on
financial instruments with similar characteristics and terms. Investments other
than cash and cash equivalents include decommissioning trust investments. The
Companies have no securities held for trading purposes. See Note 7 for
discussion of SFAS 115 activity related to available-for-sale securities.

           The  investment  policy for the nuclear  decommissioning  trust funds
restricts  or limits  the  ability  to hold  certain  types of assets  including
private or direct placements,  warrants, securities of FirstEnergy,  investments
in companies  owning  nuclear power  plants,  financial  derivatives,  preferred
stocks,  securities  convertible  into common stock and  securities of the trust
fund's custodian or managers and their parents or subsidiaries.  The investments
that are held in the  decommissioning  trusts  (included  as "All  other" in the
table  above)  consist of equity  securities  ($209  million)  and fixed  income
securities ($167 million) as of December 31, 2003. In 2001, unrealized gains and
losses  applicable to the  decommissioning  trusts were  recognized in the trust
investment with a corresponding change to the decommissioning liability. In 2003
and  2002,   unrealized   gains  and   losses   applicable   to  the   Company's
decommissioning  trusts  were  offset to OCI in  accordance  with  SFAS 115,  as
fluctuations  in the fair value of the trusts will eventually  affect  earnings.
Realized gains (losses) are recognized as additions  (reductions) to trust asset
balances  with an offset to  earnings.  For 2003 and 2002,  net  realized  gains
(losses) were approximately $5.1 million and $(3.4) million,  respectively,  and
interest  and  dividend  income  totaled  approximately  $10.0  million and $8.9
million, respectively.

2.   LEASES

           The Companies lease certain generating facilities, office space and
other property and equipment under cancelable and noncancelable leases.

           The Company sold portions of its ownership interest in Perry Unit 1
and Beaver Valley Unit 2 and entered into operating leases on the portions sold
for basic lease terms of approximately 29 years. During the terms of the leases,
the Company continues to be responsible, to the extent of its individual
combined ownership and leasehold interests, for costs associated with the units
including construction expenditures, operation and maintenance expenses,
insurance, nuclear fuel, property taxes and decommissioning. The Company has the
right, at the end of the respective basic lease terms, to renew the leases for
up to two years. The Company also has the right to purchase the facilities at
the expiration of the basic lease term or any renewal term at a price equal to
the fair market value of the facilities. The basic rental payments are adjusted
when applicable federal tax law changes.

           OES Finance, Incorporated, a wholly owned subsidiary of the Company,
maintains deposits pledged as collateral to secure reimbursement obligations
relating to certain letters of credit supporting the Company's obligations to
lessors under the Beaver Valley Unit 2 sale and leaseback arrangements. The
deposits of approximately $278 million pledged to the financial institution
providing those letters of credit are the sole property of OES Finance and are
investments which are classified as "Held to Maturity." In the event of
liquidation, OES Finance, as a separate corporate entity, would have to satisfy
its obligations to creditors before any of its assets could be made available to
the Company as sole owner of OES Finance common stock.

           Consistent with the regulatory treatment, the rentals for capital and
operating leases are charged to operating expenses on the Consolidated
Statements of Income. Such costs for the three years ended December 31, 2003,
are summarized as follows:

                               2003           2002           2001
------------------------------------------------------------------
                                           (In millions)
Operating leases
  Interest element.........   $ 96.4          $100.9        $102.7
  Other....................     41.2            34.6          31.6
Capital leases
  Interest element.........      1.7             1.6           1.9
  Other....................      1.4             1.3           1.9
------------------------------------------------------------------
  Total rentals............   $140.7          $138.4        $138.1
==================================================================


                                         30

<PAGE>


<TABLE>
<CAPTION>

           The future minimum lease payments as of December 31, 2003, are:

                                                                         Operating Leases
                                                                 -----------------------------------
                                                   Capital        Lease       PNBV Capital
                                                   Leases        Payments          Trust       Net
       ---------------------------------------------------------------------------------------------
                                                                        (In millions)
       <S>                                         <C>           <C>             <C>        <C>
       2004......................................  $ 4.3         $  137.8        $ 58.5     $   79.3
       2005......................................    4.3            138.8          56.6         82.2
       2006......................................    4.3            139.9          59.5         80.4
       2007......................................    0.3            139.3          59.9         79.4
       2008......................................    0.3            139.6          34.9        104.7
       Years thereafter..........................    1.5          1,133.0         321.6        811.4
       ---------------------------------------------------------------------------------------------
       Total minimum lease payments..............   15.0         $1,828.4        $591.0     $1,237.4
                                                                 ========        ======     ========
       Executory costs...........................    5.3
       -------------------------------------------------
       Net minimum lease payments................    9.7
       Interest portion..........................    2.9
       -------------------------------------------------
       Present value of net minimum
         lease payments..........................    6.8
       Less current portion......................    1.5
       -------------------------------------------------
       Noncurrent portion........................  $ 5.3
       =================================================

</TABLE>


           The Company invested in the PNBV Capital Trust, which was established
to purchase a portion of the lease obligation bonds issued on behalf of lessors
in the Company's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback
transactions. The PNBV capital trust arrangement effectively reduces lease costs
related to those transactions.

3.   CAPITALIZATION:

     (A) RETAINED EARNINGS-

           Under the Company's first mortgage indenture, the Company's
consolidated retained earnings unrestricted for payment of cash dividends on the
Company's common stock were $519.0 million as of December 31, 2003.

     (B) EMPLOYEE STOCK OWNERSHIP PLAN (ESOP)-

           An ESOP Trust funds most of the matching contribution for
FirstEnergy's 401(k) savings plan. All of the Companies' full-time employees
eligible for participation in the 401(k) savings plan are covered by the ESOP.
The ESOP borrowed $200 million from the Company and acquired 10,654,114 shares
of the Company's common stock (subsequently converted to FirstEnergy common
stock) through market purchases. The ESOP loan is included in Other Property and
Investments on the Consolidated Balance Sheets as of December 31, 2003 and 2002
as an investment with FirstEnergy related to the FirstEnergy savings plan.
Dividends on ESOP shares are used to service the debt. Shares are released from
the ESOP on a pro rata basis as debt service payments are made. As of December
31, 2003, the Company had approximately $49 million receivable from FirstEnergy
representing reductions to the outstanding loan balance from the ESOP Trust that
were paid to FirstEnergy since 1998 that were intended to be remitted to the
Company; that receivable will be paid in March 2004.


     (C) STOCK COMPENSATION PLANS-

         FirstEnergy administers the FirstEnergy Executive and Director
Incentive Compensation Plan (FE Plan). Under the FE Plan, total awards cannot
exceed 22.5 million shares of common stock or their equivalent. Only stock
options and restricted stock have been granted, with vesting periods ranging
from six months to seven years. Several other stock compensation plans have been
acquired through the mergers with GPU and Centerior - GPU, Inc. Stock Option and
Restricted Stock Plan for MYR Group Inc. Employees (MYR Plan), 1990 Stock Plan
for Employees of GPU, Inc. and Subsidiaries (GPU Plan) and Centerior Equity
Plan. No further stock-based compensation can be awarded under these plans.

           Collectively, the above plans are referred to as the FE Programs.
Restricted common stock grants under the FE Programs were as follows:

                                           2003         2002        2001
----------------------------------------------------------------------------

 Restricted common shares granted......     --         36,922     133,162
 Weighted average market price ........    n/a (1)     $36.04      $35.68
 Weighted average vesting period
  (years)..............................    n/a (1)        3.2         3.7
 Dividends restricted..................    n/a (1)      Yes            -- (2)
 ---------------------------------------------------------------------------

  (1) Not applicable since no restricted stock was granted.
  (2) FE Plan dividends are paid as restricted stock on 4,500
      shares; MYR Plan dividends are paid as unrestricted cash
      on 128,662 shares

                                       31
<PAGE>

           Under the Executive Deferred Compensation Plan (EDCP), covered
employees can direct a portion of their Annual Incentive Award and/or Long-Term
Incentive Award into an unfunded FirstEnergy Stock Account to receive vested
stock units. An additional 20% premium is received in the form of stock units
based on the amount allocated to the FirstEnergy Stock Account. Dividends are
calculated quarterly on stock units outstanding and are paid in the form of
additional stock units. Upon withdrawal, stock units are converted to
FirstEnergy shares. Payout typically occurs three years from the date of
deferral; however, an election can be made in the year prior to payout to
further defer shares into a retirement stock account that will pay out in cash
upon retirement. As of December 31, 2003, there were 410,399 stock units
outstanding.

           Stock option activities under the FE Programs for the past three
years were as follows:


                                           Number of      Weighted Average
      Stock Option Activities                Options          Exercise Price
------------------------------------------------------------------------------
 Balance, January 1, 2001..............    5,021,862             24.09
 (473,314 options exercisable).........                          24.11

   Options granted.....................    4,240,273             28.11
   Options exercised...................      694,403             24.24
   Options forfeited...................      120,044             28.07
 Balance, December 31, 2001............    8,447,688             26.04
 (1,828,341 options exercisable).......                          24.83

   Options granted.....................    3,399,579             34.48
   Options exercised...................    1,018,852             23.56
   Options forfeited...................      392,929             28.19
 Balance, December 31, 2002............   10,435,486             28.95
 (1,400,206 options exercisable).......                          26.07

   Options granted.....................    3,981,100             29.71
   Options exercised...................      455,986             25.94
   Options forfeited...................      311,731             29.09
 Balance, December 31, 2003............   13,648,869             29.27
 (1,919,662 options exercisable).......                          29.67


           As of December 31, 2003, the weighted average remaining contractual
life of outstanding stock options was 7.6 years.


           Options outstanding by plan and range of exercise price as of
December 31, 2003 were as follows:

                                       Range of                 Options
 FirstEnergy Program                Exercise Prices          Outstanding
 -----------------------------------------------------------------------

 FE plan                            $19.31 - $29.87           9,904,861
                                    $30.17 - $35.15           3,214,601
 Plans acquired through merger:
 GPU plan                           $23.75 - $35.92             501,734
 Other plans                                                     27,673
 ----------------------------------------------------------------------
 Total                                                       13,648,869
 ======================================================================

           No material stock-based employee compensation expense is reflected in
net income for stock options granted under the above plans since the exercise
price was equal to the market value of the underlying common stock on the grant
date. The effect of applying fair value accounting to FirstEnergy's stock
options is summarized in Note 1(G) - "Stock-Based Compensation."

     (D) PREFERRED AND PREFERENCE STOCK-

           All preferred stock may be redeemed by the Companies in whole, or in
part, with 30-60 days' notice.

           The Company has eight million authorized and unissued shares of
preference stock having no par value.

     (E) LONG-TERM DEBT-

           Each of the Companies has a first mortgage indenture under which it
issues first mortgage bonds secured by a direct first mortgage lien on
substantially all of its property and franchises, other than specifically
excepted property. The Company also has a 1998 general mortgage under which it
issues mortgage bonds based upon the pledge of a like amount of first mortgage
bonds as security. These mortgage bonds therefore effectively enjoy the same
lien on that

                                       32

<PAGE>



property. The Companies have various debt covenants under their respective
financing arrangements. The most restrictive of their debt covenants relate to
the nonpayment of interest and/or principal on debt which could trigger a
default and the maintenance of minimum fixed charge ratios and debt to
capitalization ratios. There also exists cross-default provisions among
financing arrangements of FirstEnergy and the Companies.

           Based on the amount of bonds authenticated by the respective mortgage
bond trustees through December 31, 2003, the Companies' annual sinking fund
requirements for all bonds issued under the various mortgage indentures of the
Companies amounts to $39 million. The Companies expect to deposit funds with
their respective mortgage bond trustees in 2004 that will then be withdrawn upon
the surrender for cancellation of a like principal amount of bonds, specifically
authenticated for such purposes against unfunded property additions or against
previously retired bonds. This method can result in minor increases in the
amount of the annual sinking fund requirement.

           Sinking fund requirements for first mortgage bonds and maturing
long-term debt (excluding capital leases) for the next five years are:

                                  (In millions)
  ---------------------------------------------
  2004...............................   $464
  2005...............................    227
  2006...............................      5
  2007...............................      6
  2008...............................    229
  ------------------------------------------


           Included in the table above are amounts for various variable interest
rate long-term debt which have provisions by which individual debt holders have
the option to "put back" or require the respective debt issuer to redeem their
debt at those times when the interest rate may change prior to its maturity
date. These amounts are $341.7 million, $50 million and $50 million in 2004,
2005 and 2008, respectively, which represents the next date at which the debt
holders may exercise this provision.

           The Companies' obligations to repay certain pollution control revenue
bonds are secured by several series of first mortgage bonds. Certain pollution
control revenue bonds are entitled to the benefit of irrevocable bank letters of
credit of $171.5 million and noncancelable municipal bond insurance policies of
$288.9 million to pay principal of, or interest on, the pollution control
revenue bonds. To the extent that drawings are made under the letters of credit
or policies, the Companies are entitled to a credit against their obligation to
repay those bonds. The Companies pay annual fees of 1.375% to 1.50% of the
amounts of the letters of credit to the issuing banks and are obligated to
reimburse the banks for any drawings thereunder.

           The Company had unsecured borrowings of $40 million as of December
31, 2003 under a $250 million long-term revolving credit facility agreement
which expires May 12, 2005. The Company currently pays an annual facility fee of
0.20% on the total credit facility amount. The Company had no unsecured
borrowings as of December 31, 2003 under a $125 million long-term revolving
credit facility which expires October 23, 2006. The Company currently pays an
annual facility fee of 0.25% on the total credit facility amount. The fees are
subject to change based on changes to the Company's credit ratings.

     (F) LONG-TERM DEBT: PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-

           Effective July 1, 2003, upon adoption of SFAS 150 (see Note 6), the
Companies reclassified as debt Penn's preferred stock subject to mandatory
redemption. Prior year amounts were not reclassified.

           Penn's 7.625% series has an annual sinking fund requirement for 7,500
shares.

           The Companies' preferred shares are retired at $100 per share plus
accrued dividends. Annual sinking fund requirements are approximately $750,000
in each year 2004 through 2006 and $11.25 million in 2007.

     (G) COMPREHENSIVE INCOME-

           Comprehensive income includes net income as reported on the
Consolidated Statements of Income and all other changes in common stockholder's
equity except those resulting from transactions with FirstEnergy. As of December
31, 2003, accumulated other comprehensive loss consisted of a minimum liability
for unfunded retirement benefits of $(61.9) million and unrealized gains on
investments in securities available for sale of $23.2 million.

4. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:

           Short-term borrowings outstanding as of December 31, 2003, consisted
of $21.9 million of bank borrowings and $149.7 million of OES Capital,
Incorporated commercial paper. OES Capital is a wholly owned subsidiary of the

                                       33

<PAGE>

Company whose borrowings are secured by customer accounts receivable. OES
Capital can borrow up to $170 million under a receivables financing agreement at
rates based on certain bank commercial paper and is required to pay an annual
fee of 0.50% on the amount of the entire finance limit. The receivables
financing agreement expires in October 2004. As of December 31, 2003, the
Company also had total short-term borrowings of $11.3 million from its
affiliates. The weighted average interest rates on short-term borrowings
outstanding as of December 31, 2003 and 2002, were 1.16% and 1.63%,
respectively.

           The Company has lines of credit with domestic banks that provide for
borrowings of up to $159 million under various interest rate options. Short-term
borrowings may be made under these lines of credit on its unsecured notes. To
assure the availability of these lines, the Company is required to pay annual
commitment fees of 0.20%. These lines expire at various times during 2004.

5.   COMMITMENTS AND CONTINGENCIES:

     (A) CAPITAL EXPENDITURES-

           The Companies' current forecast reflects expenditures of
approximately $438 million for property additions and improvements from
2004-2006, of which approximately $174 million is applicable to 2004.
Investments for additional nuclear fuel during the 2004-2006 period are
estimated to be approximately $82 million, of which approximately $48 million
applies to 2004. During the same periods, the Companies' nuclear fuel
investments are expected to be reduced by approximately $85 million and $43
million, respectively, as the nuclear fuel is consumed.

     (B) NUCLEAR INSURANCE-

           The Price-Anderson Act limits the public liability relative to a
single incident at a nuclear power plant to $10.9 billion. The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
Based on their ownership and leasehold interests in the Beaver Valley Station
and the Perry Plant, the Companies' maximum potential assessment under the
industry retrospective rating plan (assuming the other affiliate co-owners
contribute their proportionate shares of any assessments under the retrospective
rating plan) would be $192.0 million per incident but not more than $19.1
million in any one year for each incident.

           The Companies are also insured as to their respective interests in
Beaver Valley and Perry under policies issued to the operating company for each
plant. Under these policies, up to $2.75 billion is provided for property damage
and decontamination and decommissioning costs. The Companies have also obtained
approximately $537 million of insurance coverage for replacement power costs for
their respective interests in Beaver Valley and Perry. Under these policies, the
Companies can be assessed a maximum of approximately $29.1 million for incidents
at any covered nuclear facility occurring during a policy year which are in
excess of accumulated funds available to the insurer for paying losses.

           The Companies intend to maintain insurance against nuclear risks as
described above as long as it is available. To the extent that replacement
power, property damage, decontamination, decommissioning, repair and replacement
costs and other such costs arising from a nuclear incident at any of the
Companies' plants exceed the policy limits of the insurance in effect with
respect to that plant, to the extent a nuclear incident is determined not to be
covered by the Companies' insurance policies, or to the extent such insurance
becomes unavailable in the future, the Companies would remain at risk for such
costs.

     (C) ENVIRONMENTAL MATTERS-

           Various federal, state and local authorities regulate the Companies
with regard to air and water quality and other environmental matters. The
effects of compliance on the Companies with regard to environmental matters
could have a material adverse effect on the Companies' earnings and competitive
position. These environmental regulations affect the Companies' earnings and
competitive position to the extent that they compete with companies that are not
subject to such regulations and therefore do not bear the risk of costs
associated with compliance, or failure to comply, with such regulations.
Overall, the Companies believe they are in material compliance with existing
regulations but are unable to predict future change in regulatory policies and
what, if any, the effects of such change would be. In accordance with the Ohio
transition plan discussed in "Regulatory Matters" in Note 1(C), generation
operations and any related additional capital expenditures for environmental
compliance are the responsibility of FirstEnergy's competitive services business
unit.

         Clean Air Act Compliance

           The Companies are required to meet federally approved sulfur dioxide
(SO2) regulations. Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $31,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an interim enforcement policy for SO2

                                      34
<PAGE>



regulations in Ohio that allows for compliance based on a 30-day averaging
period. The Companies cannot predict what action the EPA may take in the future
with respect to the interim enforcement policy.

           The Companies are complying with SO2 reduction requirements under the
Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more
electricity from lower-emitting plants, and/or using emission allowances. NOx
reductions required by the 1990 Amendments are being achieved through combustion
controls and the generation of more electricity at lower-emitting plants. In
September 1998, the EPA finalized regulations requiring additional NOx
reductions from the Companies' Ohio and Pennsylvania facilities. The EPA's NOx
Transport Rule imposes uniform reductions of NOx emissions (an approximate 85%
reduction in utility plant NOx emissions from projected 2007 emissions) across a
region of nineteen states (including Ohio and Pennsylvania) and the District of
Columbia based on a conclusion that such NOx emissions are contributing
significantly to ozone pollution in the eastern United States. State
Implementation Plans (SIP) must comply by May 31, 2004 with individual state NOx
budgets established by the EPA. Pennsylvania submitted a SIP that required
compliance with the NOx budgets at the Companies' Pennsylvania facilities by May
1, 2003. The Companies' Pennsylvania facilities complied with the NOx budgets in
2003 and all facilities will comply with the NOx budgets in 2004 and thereafter.
Ohio submitted a SIP that requires compliance with the NOx budgets at the
Companies' Ohio facilities by May 31, 2004.

         National Ambient Air Quality Standards

           In July 1997, the EPA promulgated changes in the National Ambient Air
Quality Standard (NAAQS) for ozone and proposed a new NAAQS for fine particulate
matter. On December 17, 2003, the EPA proposed the "Interstate Air Quality Rule"
covering a total of 29 states (including Ohio and Pennsylvania) and the District
of Columbia based on proposed findings that air pollution emissions from 29
eastern states and the District of Columbia significantly contribute to
nonattainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in
other states. The EPA has proposed the Interstate Air Quality Rule to
"cap-and-trade" NOx and SO2 emissions in two phases (Phase I in 2010 and Phase
II in 2015). According to the EPA, SO2 emissions would be reduced by
approximately 3.6 million tons in 2010, across states covered by the rule, with
reductions ultimately reaching more than 5.5 million tons annually. NOx emission
reductions would measure about 1.5 million tons in 2010 and 1.8 million tons in
2015. The future cost of compliance with these proposed regulations may be
substantial and will depend if and how they are ultimately implemented by the
states in which the Companies operate affected facilities.

         Mercury Emissions

           In December 2000, the EPA announced it would proceed with the
development of regulations regarding hazardous air pollutants from electric
power plants, identifying mercury as the hazardous air pollutant of greatest
concern. On December 15, 2003, the EPA proposed two different approaches to
reduce mercury emissions from coal-fired power plants. The first approach would
require plants to install controls known as "maximum achievable control
technologies" (MACT) based on the type of coal burned. According to the EPA, if
implemented, the MACT proposal would reduce nationwide mercury emissions from
coal-fired power plants by fourteen tons to approximately thirty-four tons per
year. The second approach proposes a cap-and-trade program that would reduce
mercury emissions in two distinct phases. Initially, mercury emissions would be
reduced by 2010 as a "co-benefit" from implementation of SO2 and NOx emission
caps under the EPA's proposed Interstate Air Quality Rule. Phase II of the
mercury cap-and-trade program would be implemented in 2018 to cap nationwide
mercury emissions from coal-fired power plants at fifteen tons per year. The EPA
has agreed to choose between these two options and issue a final rule by
December 15, 2004. The future cost of compliance with these regulations may be
substantial.

         W. H. Sammis Plant

           In 1999 and 2000, the EPA issued Notices of Violation (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis Plant. In addition, the U.S. Department of Justice filed eight civil
complaints against various investor-owned utilities, which included a complaint
against the Companies in the U.S. District Court for the Southern District of
Ohio. The NOV and complaint allege violations of the Clean Air Act based on
operation and maintenance of the W. H. Sammis Plant dating back to 1984. The
complaint requests permanent injunctive relief to require the installation of
"best available control technology" and civil penalties of up to $27,500 per day
of violation. On August 7, 2003, the United States District Court for the
Southern District of Ohio ruled that 11 projects undertaken at the W. H. Sammis
Plant between 1984 and 1998 required pre-construction permits under the Clean
Air Act. The ruling concludes the liability phase of the case, which deals with
applicability of Prevention of Significant Deterioration provisions of the Clean
Air Act. The remedy phase, which is currently scheduled to be ready for trial
beginning July 19, 2004, will address civil penalties and what, if any, actions
should be taken to further reduce emissions at the plant. In the ruling, the
Court indicated that the remedies it "may consider and impose involved a much
broader, equitable analysis, requiring the Court to consider air quality, public
health, economic impact, and employment consequences. The Court may also
consider the less than consistent efforts of the EPA to apply and further
enforce the Clean Air Act." The potential penalties that may be imposed, as well
as the capital expenditures necessary to comply with substantive remedial
measures that may be required, could have a material adverse impact on the
Companies' financial condition


                                          35
<PAGE>


and results of operations. Management is unable to predict the ultimate outcome
of this matter and no liability has been accrued as of December 31, 2003.

         Regulation of Hazardous Waste

           As a result of the Resource Conservation and Recovery Act of 1976, as
amended, and the Toxic Substances Control Act of 1976, federal and state
hazardous waste regulations have been promulgated. Certain fossil-fuel
combustion waste products, such as coal ash, were exempted from hazardous waste
disposal requirements pending the EPA's evaluation of the need for future
regulation. The EPA subsequently determined that regulation of coal ash as a
hazardous waste is unnecessary. In April 2000, the EPA announced that it will
develop national standards regulating disposal of coal ash under its authority
to regulate nonhazardous waste.

         Climate Change

           In December 1997, delegates to the United Nations' climate summit in
Japan adopted an agreement, the Kyoto Protocol (Protocol), to address global
warming by reducing the amount of man-made greenhouse gases emitted by developed
countries by 5.2% from 1990 levels between 2008 and 2012. The United States
signed the Protocol in 1998 but it failed to receive the two-thirds vote of the
U.S. Senate required for ratification. However, the Bush administration has
committed the United States to a voluntary climate change strategy to reduce
domestic greenhouse gas intensity - the ratio of emissions to economic output -
by 18% through 2012.

           The Companies cannot currently estimate the financial impact of
climate change policies although the potential restrictions on carbon dioxide
(CO2) emissions could require significant capital and other expenditures.
However, the CO2 emissions per kilowatt-hour of electricity generated by the
Companies is lower than many regional competitors due to the Companies'
diversified generation sources which includes low or non-CO2 emitting gas-fired
and nuclear generators.

         Clean Water Act

           Various water quality regulations, the majority of which are the
result of the federal Clean Water Act and its amendments, apply to the
Companies' plants. In addition, Ohio and Pennsylvania have water quality
standards applicable to the Companies' operations. As provided in the Clean
Water Act, authority to grant federal National Pollutant Discharge Elimination
System water discharge permits can be assumed by a state. Ohio and Pennsylvania
have assumed such authority.

     (D) LEGAL MATTERS-

           Various lawsuits, claims and proceedings related to the Companies'
normal business operations are pending against FirstEnergy and its subsidiaries.
On August 14, 2003, eight states and parts of southern Canada experienced a
widespread power outage. That outage affected approximately 1.4 million
customers in FirstEnergy's service area. FirstEnergy continues to accumulate
data and evaluate the status of its electrical system prior to and during the
outage event, and continues to cooperate with the U.S.-Canada Power System
Outage Task Force (Task Force) investigating the August 14th outage. The interim
report issued by the Task Force on November 18, 2003 concluded that the problems
leading to the outage began in FirstEnergy's service area. Specifically, the
interim report concludes, among other things, that the initiation of the August
14th outage resulted from the coincidence on that afternoon of the following
events: (1) inadequate situational awareness at FirstEnergy; (2) FirstEnergy's
failure to adequately manage tree growth in its transmission rights of way; and
(3) failure of the interconnected grid's reliability organizations (Midwest
Independent System Operator and PJM Interconnection) to provide effective
diagnostic support. FirstEnergy believes that the interim report falls far short
of providing a complete and comprehensive picture of the conditions that
contributed to the August 14th outage and that it does not adequately address
the underlying causes of the outage. FirstEnergy remains convinced that the
outage cannot be explained by events on any one utility's system. On November
25, 2003, the PUCO ordered FirstEnergy to file a plan with the PUCO no later
than March 1, 2004, illustrating how FirstEnergy will correct problems
identified by the Task Force as events contributing to the August 14th outage
and addressing how FirstEnergy proposes to upgrade its control room computer
hardware and software and improve the training of control room operators to
ensure that similar problems do not occur in the future. The PUCO, in
consultation with the North American Electric Reliability Council, will review
the plan before determining the next steps in the proceeding. On December 24,
2003, the FERC ordered FirstEnergy to pay for an independent study of part of
Ohio's power grid. The study is to examine the stability of the grid in critical
points in the Cleveland and Akron areas; the status of projected power reserves
during summer 2004 through 2008; and the need for new transmission lines or
other grid projects. The FERC ordered the study to be completed within 120 days.
At this time, it is unknown what the cost of such study will be, or the impact
of the results.

                                     36
<PAGE>


6.   NEW ACCOUNTING STANDARDS AND INTERPRETATIONS:

       FIN 46 (revised December 2003), "Consolidation of Variable Interest
       Entities"

           In December 2003, the FASB issued a revised interpretation of
Accounting Research Bulletin No. 51, "Consolidated Financial Statements." FASB
Interpretation No. 46, "Consolidation of Variable Interest Entities", referred
to as "FIN 46R", requires the consolidation of a VIE by an enterprise if that
enterprise is determined to be the primary beneficiary of the VIE. As required,
the Companies adopted FIN 46R for interests in VIEs or potential VIEs commonly
referred to as special-purpose entities effective December 31, 2003. The
Companies will adopt FIN 46R for all other types of entities effective March 31,
2004.

           The Company currently has transactions with entities in connection
with sale and leaseback arrangements which fall within the scope of this
interpretation and which meet the definition of a VIE in accordance with FIN
46R. Upon adoption of FIN 46R effective December 31, 2003, the Company
consolidated the PNBV Capital Trust (PNBV) which was created in 1996 to
refinance debt in connection with sale and leaseback transactions. Consolidation
of PNBV changed the trust investment of $361 million to an investment in
collateralized lease bonds of $372 million. The $11 million increase represents
the minority interest in the total assets of the trust.

           In reviewing the sale and leaseback arrangements, the Company also
evaluated its interest in the owner trusts that acquired interests in the Perry
Plant and Beaver Valley Unit 2. The Company was determined not to be the primary
beneficiary of any of these owner trusts and was therefore not required to
consolidate these entities. The leases are accounted for as operating leases in
accordance with GAAP and their related obligations are disclosed in Note 2.

       SFAS 150, "Accounting for Certain Financial Instruments with
       Characteristics of both Liabilities and Equity"

           In May 2003, the FASB issued SFAS 150, which establishes standards
for how an issuer classifies and measures certain financial instruments with
characteristics of both liabilities and equity. In accordance with the standard,
financial instruments that embody obligations for the issuer are required to be
classified as liabilities. SFAS 150 was effective immediately for financial
instruments entered into or modified after May 31, 2003 and effective at the
beginning of the first interim period beginning after June 15, 2003 for all
other financial instruments.

           Upon adoption of SFAS 150, effective July 1, 2003, the Company
reclassified as debt the preferred stock of consolidated subsidiaries subject to
mandatory redemption with a carrying value of approximately $14 million as of
December 31, 2003. Prior to the adoption of SFAS 150, subsidiary preferred
dividends on the Company's Consolidated Statements of Income were included in
net interest charges. Therefore, the application of SFAS 150 did not require the
reclassification of such preferred dividends to net interest charges.

       SFAS 143, "Accounting for Asset Retirement Obligations"

           In January 2003, the Companies implemented SFAS 143 which provides
accounting standards for retirement obligations associated with tangible
long-lived assets. This statement requires recognition of the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred. See Notes 1(F) and 1(I) for further discussions of SFAS 143.

       EITF  Issue  No.  03-1,  "The  Meaning  of  Other-Than-Temporary
       Impairment  and its  Application  to  Certain Investments"

           In November 2003, the EITF reached consensus that certain
quantitative and qualitative disclosures are required for debt and equity
securities classified as available-for-sale or held-to-maturity. The guidance
requires the disclosure of the aggregate amount of unrealized losses and the
aggregate related fair value for investments with unrealized losses that have
not been recognized as other-than-temporary impairments. The Company has adopted
the disclosure requirements of EITF Issue No. 03-1 as of December 31, 2003 (See
Note 7(C)).

7.   OTHER INFORMATION:

           The following financial data provides supplemental unaudited
information to the consolidated financial statements previously reported in
2001:

                                       37
<PAGE>


     (A) Consolidated Statements of Cash Flows
                                                                     (Unaudited)
                                              2003         2002          2001
                                              ----         ----          ----
                                                       (In thousands)
 Other Cash Flows From Operating Activities:
 Accrued taxes...........................   $ 94,281     $208,945     $ 26,606
 Accrued interest........................     (9,495)      (4,844)      (1,053)
 Prepayments and other...................     (2,586)      38,737       26,393
 All other...............................     68,299      (29,909)     (76,858)
 -----------------------------------------------------------------------------
   Total-Other...........................   $150,499     $212,929     $(24,912)
==============================================================================

 Other Cash Flows from Investing Activities:
 Asset retirements and transfers.........   $  2,095     $  7,476     $ 15,528
 Nuclear decommissioning trust
   investments...........................    (83,178)     (15,688)     (15,816)
 Other investments.......................     55,127       18,820        3,209
 All other...............................         99       23,524          (33)
 -----------------------------------------------------------------------------
   Total-Other...........................   $(25,857)    $ 34,132     $  2,888
==============================================================================


     (B) Consolidated Statements of Taxes
                                                                   (Unaudited)
                                              2003         2002         2001
                                              ----         ----         ----
                                                      (In thousands)
Other Accumulated Deferred Income
  Taxes at December 31:
Retirement Benefits.....................    $(29,676)    $ 20,969     $ 24,591
All other...............................     141,063       63,344       40,295
------------------------------------------------------------------------------
  Total-Other...........................    $111,387     $ 84,313     $ 64,886
==============================================================================


     (C) SFAS 115 Activity

           Investments other than cash and cash equivalents in the table in Note
1(L) - Cash and Financial Instruments include available-for-sale securities, at
fair value, with the following net results:


                                         2003*            2002*
---------------------------------------------------------------
                                           (In millions)
Unrealized gains (losses)...........    $ 30.7          $(17.5)
Proceeds from sales.................     142.3            71.5
Realized gains (losses).............       3.9            (3.1)
---------------------------------------------------------------

 * Includes the available-for-sale securities of the Companies'
   decommissioning trusts.


           As of December 31, 2003 accumulated other comprehensive income (loss)
for available-for-sale securities consisted of investments with net unrealized
gains of $48.1 million and net unrealized losses of $6.8 million. The following
table provides details for the available-for-sale securities with net unrealized
losses as of December 31, 2003.


<TABLE>
<CAPTION>


                           Less Than 12 Months          12 Months or More                 Total
                          --------------------         --------------------       ---------------------
                           Fair      Unrealized        Fair     Unrealized        Fair      Unrealized
Security Type             Value        Losses          Value      Losses          Value        Losses
-------------------------------------------------------------------------------------------------------
                                                          (In millions)
<S>                        <C>           <C>            <C>          <C>           <C>            <C>
Equity Securities.......    3.7          1.1            21.0          5.6          24.7           6.7
Debt Securities.........   15.1          0.1             0.1         --            15.2           0.1
-----------------------------------------------------------------------------------------------------

    Total...............   18.8          1.2            21.1          5.6          39.9           6.8
-------------------------------------------------------------------------------------------------------

</TABLE>


           All of the aggregate unrealized losses related to available-for-sale
securities in the table above are considered to be temporary in nature. These
securities are primarily held by the Company's nuclear decommissioning trusts.
The Company has the ability and intent to hold these securities for the period
necessary to fund their cost.

                                                     38
<PAGE>


8. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):

           The following summarizes certain consolidated operating results by
quarter for 2003 and 2002.


<TABLE>
<CAPTION>

                                                    March 31,      June 30,      September 30,       December 30,
        Three Months Ended                            2003           2003            2003                2003(a)
-------------------------------------------------------------------------------------------------------------------
                                                                         (In millions)

<S>                                                   <C>           <C>              <C>                <C>
Operating Revenues...............................     $742.8        $673.7           $774.9             $734.4
Operating Expenses and Taxes.....................      672.7         609.7            686.9              620.8
-------------------------------------------------------------------------------------------------------------------
Operating Income.................................       70.1          64.0             88.0              113.6
Other Income.....................................       13.5          15.4             16.5               22.6
Net Interest Charges.............................       26.5          34.1             23.6               26.6
-------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of Accounting
   Change........................................       57.1          45.3             80.9              109.6
Cumulative Effect of Accounting Change (Net of
   Income Taxes).................................       31.7          --               --                 --
Net Income.......................................     $ 88.8        $ 45.3           $ 80.9             $109.6
===================================================================================================================
Earnings on Common Stock.........................     $ 88.1        $ 44.7           $ 80.1             $109.0
===================================================================================================================


<CAPTION>


                                                     March 31,     June 30,        September 30,     December 31,
        Three Months Ended                            2002           2002             2002               2002
-------------------------------------------------------------------------------------------------------------------
                                                                         (In millions)

<S>                                                   <C>           <C>              <C>                <C>
Operating Revenues...............................     $707.8        $744.5           $813.3             $683.1
Operating Expenses and Taxes.....................      600.4         611.1            664.5              618.8
-------------------------------------------------------------------------------------------------------------------
Operating Income.................................      107.4         133.4            148.8               64.3
Other Income.....................................        0.5          15.1             14.2               13.0
Net Interest Charges.............................       41.2          35.9             33.7               29.8
-------------------------------------------------------------------------------------------------------------------
Net Income.......................................     $ 66.7        $112.6           $129.3             $ 47.5
===================================================================================================================
Earnings on Common Stock.........................     $ 64.0        $110.1           $128.6             $ 46.9
===================================================================================================================

<FN>

(a)  Net income for the three months ended December 31, 2003, was increased by
     $3.5 million due to adjustments that were subsequently capitalized to
     construction projects in the fourth quarter. The adjustments included $0.6
     million, $1.0 million and $1.9 million of costs charged to expense in the
     first, second and third quarters, respectively. Management concluded that
     the adjustments were not material to the consolidated financial statements
     for any quarter of 2003.


</FN>
</TABLE>

                                          39


<PAGE>


Report of Independent Auditors

To the Stockholders and Board of Directors of Ohio Edison Company:


In our opinion, the accompanying consolidated balance sheets and consolidated
statements of capitalization and the related consolidated statements of income,
common stockholder's equity, preferred stock, cash flows and taxes present
fairly, in all material respects, the financial position of Ohio Edison Company
(a wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December
31, 2003 and 2002 and the results of their operations and their cash flows for
the years then ended in conformity with accounting principles generally accepted
in the United States of America. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with auditing standards generally
accepted in the United States of America, which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion. The
consolidated financial statements of Ohio Edison Company and subsidiaries for
the year ended December 31, 2001, prior to the revision described in Note 1(F),
were audited by other independent auditors who have ceased operations. Those
independent auditors expressed an unqualified opinion on those financial
statements in their report dated March 18, 2002.

As discussed in Note 1(F) to the consolidated financial statements, the Company
changed its method of accounting for asset retirement obligations as of January
1, 2003. As discussed in Note 6 to the consolidated financial statements, the
Company changed its method of accounting for the consolidation of variable
interest entities as of December 31, 2003.

As discussed above, the consolidated financial statements of Ohio Edison Company
and subsidiaries for the year ended December 31, 2001 were audited by other
independent auditors who have ceased operations. As described in Note 1(F) to
the consolidated financial statements, the financial statements have been
revised to include the transitional disclosures required by Statement of
Financial Accounting Standards No. 143, Accounting for Asset Retirement
Obligations, which was adopted by the Company as of January 1, 2003. We audited
the transitional disclosures described in Note 1(F). In our opinion, the
transitional disclosures for 2001 are appropriate. However, we were not engaged
to audit, review, or apply any procedures to the 2001 consolidated financial
statements of the Company other than with respect to such transitional
disclosures and, accordingly, we do not express an opinion or any other form of
assurance on the 2001 consolidated financial statements taken as a whole.





PricewaterhouseCoopers LLP
Cleveland, Ohio
February 25, 2004

                                      40

<PAGE>


The following report is a copy of a report previously issued by Arthur Andersen
LLP (Andersen). This report has not been reissued by Andersen and Andersen did
not consent to the incorporation by reference of this report into any of the
Company's registration statements.

As discussed in Note 1(F) to the consolidated financial statements, the Company
has revised its consolidated financial statements for the year ended December
31, 2001 to include the transitional disclosures required by Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations." The Andersen report does not extend to these changes. The
revisions to the 2001 financial statements related to these transitional
disclosures were reported on by PricewaterhouseCoopers LLP, as stated in their
report appearing herein.


Report of Independent Public Accountants

To the Stockholders and Board of Directors of Ohio Edison Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Ohio Edison Company (an Ohio corporation and
wholly owned subsidiary of FirstEnergy Corp.) and subsidiaries as of December
31, 2001 and 2000, and the related consolidated statements of income, common
stockholder's equity, preferred stock, cash flows and taxes for each of the
three years in the period ended December 31, 2001. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Ohio Edison Company and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.






ARTHUR ANDERSEN LLP

Cleveland, Ohio,
   March 18, 2002.


                                     41
<PAGE>